UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-K/A

  (Mark one)
     [X]  Annual  Report  pursuant  to  Section  13 or 15(d)  of the  Securities
Exchange Act of 1934 For the fiscal year ended December 31, 2000

     [ ]  Transition  Report  pursuant to Section 13 or 15(d) of the  Securities
Exchange Act of 1934 For the transition period from __________ to ___________ .


                           Commission File No. 1-12508

                          MAGNUM HUNTER RESOURCES, INC.
             (Exact name of registrant as specified in its charter)

                 Nevada                             87-0462881
              ------------                      ------------------
        State or other jurisdiction of           (I.R.S. Employer
        incorporation or organization            Identification No.)


           600 East Las Colinas Blvd., Suite 1100, Irving, Texas 75039
           -----------------------------------------------------------
               (Address of principal executive offices) (zip code)


       Registrant's telephone number, including area code: (972) 401-0752

      Securities registered pursuant to Section 12(b) of the Exchange Act:

     Title of each class           Name of each exchange on which registered
     -------------------           -----------------------------------------
Common Stock ($.002 par value)              American Stock Exchange


           Securities registered under Section 12(g) of the Act: None

     Indicate  by check mark  whether the  registrant  (1) has filed all reports
required to be filed by Section 13 or 15(d) of the  Securities  Exchange  Act of
1934  during  the  preceding  12 months  (or for such  shorter  period  that the
registrant was required to file such reports),  and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

     Indicate by check mark if disclosure of delinquent  filers pursuant to Item
405 of regulation S-K is not contained herein, and will not be contained, to the
best of registrant's  knowledge,  in definitive proxy or information  statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]

     As of March 20, 2001,  the  aggregate  market value of voting stock held by
non-affiliates,  computed by reference  to the closing  price as reported by the
American Stock Exchange, was $272,795,355.

     The number of shares outstanding of the registrant's  common stock at March
20, 2001 was 35,399,739.
<PAGE>

                                TABLE OF CONTENTS

                       Securities and Exchange Commission
                           Item Number and Description


                                     PART I

Item 1.    Business............................................................1
            The Company........................................................1
            Business Strategy .................................................2
            Properties ........................................................3
            Development and Exploration Activities ............................7
            Gathering and Processing of Gas ...................................9
            Marketing of Production ..........................................10
            Petroleum Management and Consulting Services .....................10
            Competition.......................................................11
            Regulation .......................................................11
            Employees ........................................................13
            Facilities .......................................................13
            Risk Factors......................................................13
Item 2.    Description of Properties..........................................19
            Oil and Gas Reserves .............................................19
            Oil and Gas Production, Prices and Costs .........................22
            Drilling Activity ................................................23
            Oil and Gas Wells ................................................24
            Oil and Gas Acreage ..............................................24
Item 3.    Legal Proceedings..................................................25
Item 4.    Submission of Matters to a Vote of Security Shareholders...........25

                                     PART II

Item 5.    Market for Common Equity and Related Stockholder Matters...........25
Item 6.    Selected Financial Data............................................26
Item 7.    Management's Discussion and Analysis of Financial Condition
             and Results of Operations........................................28
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk.........37
Item 8.    Financial Statements and Supplementary Data.......................F-1
Item 9.    Change in and Disagreements with Accountants on Accounting
             and Financial Disclosure.........................................39

                                    PART III

Item 10.  Directors and Executive Officers of the Registrant..................39
Item 11.  Executive Compensation..............................................44
Item 12.  Security Ownership of Certain Beneficial Owners and Management......47
Item 13.  Certain Relationships and Related Transactions......................48
          Glossary............................................................49
Item 14.  Exhibits, Financial Statement Schedule and Reports on Form 8-K......52
<PAGE>

                                     PART I

                SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

     Certain  statements  in this Form 10-K under "Item 1.  Business,"  "Item 7.
Management's  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations"  and  elsewhere  in  this  Form  10-K  constitute   "forward-looking
statements"  within the meaning of Section 27A of the Securities Act of 1933, as
amended, and Section 21B of the Securities Exchange Act of 1934, as amended. All
statements,  other than  statements of historical  facts,  included in this Form
10-K  that  address  activities,  events  or  developments  that  Magnum  Hunter
Resources,  Inc. and its  subsidiaries  (collectively,  the "Company")  expects,
projects,  believes or  anticipates  will or may occur in the future,  including
such matters as oil and gas reserves,  future  drilling and  operations,  future
production of oil and gas,  future net cash flows,  future capital  expenditures
and other such matters,  are forward-looking  statements.  Such  forward-looking
statements  involve  known and unknown  risks,  uncertainties  and other factors
which may cause the actual  results,  performance or achievements of the Company
to be materially different from any future results,  performance or achievements
expressed or implied by such forward-looking  statements.  Such factors include,
among others, the following: the volatility of oil and gas prices, the Company's
drilling results, the Company's ability to replace reserves, the availability of
capital  resources,  the reliance upon estimates of proved  reserves,  operating
hazards and uninsured risks, competition,  government regulation, the ability of
the Company to implement its business  strategy and other factors  referenced in
this Form 10-K.

Item 1.           Business

The Company

     Magnum Hunter Resources, Inc., a Nevada corporation ("Magnum Hunter" or the
"Company"),  is an  independent  energy  company  engaged  in  the  exploration,
exploitation  and  development,   acquisition  and  operation  of  oil  and  gas
properties  with a geographic  focus in the  Mid-Continent  Region,  the Permian
Basin  and the  Gulf  Coast/Gulf  of  Mexico.  In  December  1995,  the  Company
consummated  the  acquisition of all of the  subsidiaries  of Hunter  Resources,
Inc., a Pennsylvania  corporation,  and the management of Hunter Resources, Inc.
assumed operating control of the Company.  The new management team implemented a
business  strategy that emphasized  acquisitions  of long-lived  Proved Reserves
with significant  exploitation and development  opportunities  where the Company
generally  could  control  the  operations  of the  properties.  As part of this
strategy,   from  1996  through  1999,  the  Company  acquired  properties  from
Burlington  Resources  Inc.  ("Burlington"),  Spirit Energy 76 ("Spirit  76"), a
business unit of Union Oil Company of  California,  and Vastar  Resources,  Inc.
("Vastar").  In addition to its focus on selected exploratory drilling prospects
in the Gulf of Mexico as  described  below,  the Company  intends to continue to
concentrate   its  efforts  on  additional   producing   property   acquisitions
strategically   located  in  its  geographic  area  of  operations  and  on  its
substantial  inventory of exploration,  exploitation  and  development  drilling
opportunities.  The Company also has identified  over 237  development  drilling
locations  (including both production and injection  wells) on its properties to
which  proved  reserves  have been  attributed,  substantially  all of which are
low-risk in-fill drilling opportunities.

     In 1998, the Company  acquired  approximately  a 40%  beneficial  ownership
interest in TEL Offshore  Trust  ("TEL"),  a trust created under the laws of the
state of Texas  pursuant to a cash tender offer for an aggregate  purchase price
of approximately $10.4 million.  The principal asset of TEL consists of a 99.99%
interest  in the TEL  Offshore  Trust  partnership.  Chevron  USA Inc.  owns the
remaining .01% interest in the  partnership.  The partnership owns an overriding
royalty interest equivalent to a 25% net profits interest in certain oil and gas
properties  located  offshore  Louisiana  in the  shallow  waters in the Gulf of
Mexico.

     Additionally,  the Company owns over 480 miles of gas gathering systems and
a 50% or greater  ownership  interest  in three gas  processing  plants that are
located  adjacent to certain  Company-owned  and operated  producing  properties
located in the states of Texas, Oklahoma and Arkansas.
<PAGE>

     At December  31,  2000,  the Company had an interest in 3,043 wells and had
estimated   Proved   Reserves  of  367  Bcfe  with  a  PV-10  of  $1.1  billion.
Approximately 72% of these reserves were Proved Developed  Reserves and 45% were
attributable to the Mid-Continent  Region,  45% were attributable to the Permian
Basin,  and 10% were  attributable to the Gulf  Coast/Gulf of Mexico Region.  At
December 31, 2000, the Company's  Proved Reserves had an estimated  Reserve Life
of  approximately  14 years and were 63.5%  natural gas.  The Company  serves as
operator for approximately  71% of its properties,  based on the gross number of
producing wells in which the Company owns an interest and 81% of its properties,
based upon the year-end PV-10 value.

     As a result of its property acquisitions and successful drilling activities
during 2000, the Company has achieved growth as described below:

     o After  taking into account the  Company's  divestitures  in 2000,  Proved
Reserves  increased  7% to 367.0  Bcfe at  year-  end 2000  from  341.1  Bcfe at
year-end 1999;

     o PV-10 increased 197% to $1.1 billion at year-end 2000 from $370.1 million
at year-end 1999; and

     o Average  daily  production  increased 2% to 74.8 MMcfe during fiscal 2000
from 73.6 MMcfe in fiscal 1999. The Company had an exit rate of approximately 82
MMcfe at year-end 2000.

Recent Activities

     Federal  Lease Sale.  The Company was the high bidder on 45 separate  lease
blocks at the Central Gulf of Mexico Federal Lease sale held March 28, 2001. The
Company bid the  majority  of the blocks  with a 25% - 50%  working  interest in
partnership with other companies,  including  Remington Oil and Gas Corporation,
Chieftain  International,  Inc.  and The Wiser Oil  Company.  These  blocks  are
generally   located   in  less  than  150  feet  of  water  and  near   existing
infrastructure.

     Strategic Alliance.  On May 23, 2000, the Company and GE Capital Structured
Finance Group formed a new  partnership,  Mallard Hunter LP, to acquire  certain
oil and gas reserves from two of the Company's subsidiaries.  The Company, which
is the  general  partner,  received  an  initial  1%  interest  in  the  limited
partnership. The Company's partner received an initial 99% interest as a limited
partner in the  limited  partnership  for an  initial  capital  contribution  of
approximately  $22.9  million.  The  limited  partnership  thereafter  purchased
approximately 20 billion cubic feet equivalent of proved producing reserves from
the Company's  subsidiaries for approximately  $23.2 million,  which represented
99% of the value of such  reserves  (the Company  having  contributed  1% of the
value  for its 1%  interest  in the  limited  partnership).  The  reserves  were
approximately  60% oil and 40% natural  gas.  The Company  used the net proceeds
received from the limited  partnership to reduce commercial bank indebtedness on
its two existing  credit lines. At such time as the limited partner has received
distributions  from the limited  partnership  equal to its $22.9 million initial
capital  contribution,  any  subsequent  capital  contributions  and an interest
component,  the  Company's  and the limited  partner's  interests in the limited
partnership will thereafter be 35% and 65%, respectively.

     Divestiture  of  Properties.  On August 31, 2000, the Company sold non-core
natural gas reserves  associated  with 107 producing wells in the Sonora area of
West Texas to Louis Dreyfus  Natural Gas Corp., a major operator and producer of
natural gas in the Sawyer  (Canyon)  Field.  The sales price was $15.75 million,
before  post-closing  adjustments,  and had a July 1, 2000 effective date. These
properties were originally acquired by Magnum Hunter in May 1997 from Burlington
Resources,  Inc.  Proceeds  from the sale  were  used to  reduce  the  Company's
commercial bank indebtedness.

Business Strategy

     The Company's objective is to increase its reserves,  production, cash flow
and earnings utilizing a program of (i) a selective  exploration  program;  (ii)
exploitation  and  development  of  acquired  properties,  and  (iii)  strategic
acquisitions of Proved Reserves.

     The following are key elements of the Company's strategy:

                                        2
<PAGE>

     Exploration.  The  Company  is  participating  in  drilling  Gulf of Mexico
exploratory  wells in an effort to add shorter- lived,  higher output production
to its reserve mix. The use of 3-D seismic as a tool in its exploratory drilling
in the Gulf of Mexico  has to date  been  highly  effective.  The  Company  also
attempts to align itself with active Gulf of Mexico  industry  partners who have
similar philosophies and goals with respect to a "fast track" program in placing
new  production  online.  This typically  involves  drilling wells near existing
infrastructure  such as production  platforms,  facilities  and  pipelines.  The
Company  also has an active  onshore  exploration  program  concentrated  in its
various areas of operation.

     Exploitation  and  Development  of Existing  Properties.  The Company has a
substantial  inventory of exploitation  projects including development drilling,
workovers  and  recompletions.  The Company  seeks to maximize  the value of its
properties   through   development   activities   including   in-fill  drilling,
waterflooding and other enhanced recovery techniques.

     Property  Acquisitions.  Although the Company has an extensive inventory of
exploitation  and development  opportunities,  it continues to pursue  strategic
acquisitions which fit its objectives of having Proved Reserves with development
potential and operating control.

     Management of Operating Costs. The Company  emphasizes strict cost controls
in all  aspects of its  business  and seeks to operate its  properties  wherever
possible.  By operating  approximately  71% of its properties  (81% of its PV-10
value),  the Company is generally able to control direct  operating and drilling
costs as well as to manage the timing of development and exploration activities.

     Expansion  of Gas  Gathering,  Processing  and  Marketing  Operations.  The
Company has implemented  several  programs to expand and increase the efficiency
of its gas gathering  systems and gas processing  plants.  The Company owns over
56% and markets  directly and  indirectly  approximately  88% of the natural gas
that moves through its gas gathering systems and,  therefore,  benefits from any
cost and productivity improvements. In December 1997, the Company acquired a 30%
interest in NGTS, LLC ("NGTS"),  a natural gas marketing  company  marketing gas
for third parties in the amount of approximately 375 MMcf per day as of December
31, 2000. At December 31, 2000, NGTS marketed approximately 30% of the Company's
natural  gas.  The Company  will  consider  opportunities  to acquire or develop
additional gas gathering and processing  facilities that are associated with its
current production.

Properties

     The  Company's  major  properties  are  located  in  three  areas:  (i) the
Mid-Continent  Region,  (ii) the Permian Basin and (iii) the Gulf  Coast/Gulf of
Mexico.

Mid-Continent Region

     The Company's  properties located in the Mid-Continent Region were acquired
principally from Burlington, Spirit 76 and Vastar.

     On June 28, 1996, the Company  purchased from  Burlington  interests in 520
gas wells in the Texas Panhandle and western Oklahoma, all of which are operated
by the Company,  and an associated  427 mile gas  gathering  system (the "Panoma
Properties").  As of year-end  2000,  the Company had drilled an  additional  90
wells and net  production was  approximately  12.5 million cubic feet of natural
gas per day. The net purchase price for this  acquisition in 1996, after certain
purchase price  adjustments,  was $34.7 million,  funded by borrowings under the
Company's  previous  senior  credit  facility.  Gruy is the  operator of the gas
gathering system and the wells that were previously operated by Burlington.

     On  December  31,  1998 the  Company  acquired  from  Spirit 76 natural gas
reserves and associated assets in producing fields located in Oklahoma and Texas
producing  approximately 11 million cubic feet of natural gas equivalent per day
net to the  Company.  The purchase  price was  approximately  $25 million  after
certain purchase price adjustments  including  preferential  rights exercised by
third parties and other customary adjustments.

                                       3
<PAGE>

     In June 1999, the Company  acquired  Vastar's  interest in 476 wells, a gas
processing  plant and two gas gathering  systems located in the states of Texas,
Oklahoma  and  Arkansas.  The total  purchase  price was  $32.5  million,  after
purchase  price  adjustments,  including an April 1, 1999  effective  date.  The
reserves  and  related  assets are  located  in the  Walnut  Bend Field in North
Central Texas, the Madill Field in Southern Oklahoma, and the Walker Creek Field
in Southwestern  Arkansas.  The Company's  working interests in the three fields
range from 19% to 100%. For December 2000, the three fields  generated net sales
of approximately 816 barrels per day of liquids and 3 million cubic feet per day
of natural gas production (total 8 million cubic feet equivalents per day).

     The Company has received an engineering evaluation from Ryder Scott Company
("Ryder Scott") and Cawley,  Gillespie & Associates,  Inc. ("Cawley Gillespie"),
independent petroleum engineers engaged by the Company to evaluate the Company's
properties,  on the net reserves in the Mid-Continent Region. According to Ryder
Scott  and  Cawley  Gillespie,  as  of  December  31,  2000,  the  Mid-Continent
properties had Proved  Reserves of 8 MMBbl of oil and 119 Bcf of natural gas, or
on a Natural Gas Equivalent  basis,  166 Bcfe.  Ryder Scott and Cawley Gillespie
further estimated the PV-10 for the Mid-Continent  properties to be $505 million
as of December 31, 2000.  The Proved  Reserves  are located  principally  in the
Ardmore Basin in south central Oklahoma, in the Oklahoma/Texas  panhandle and in
Southwestern  Arkansas.  Approximately 71% of the estimated reserves are natural
gas and 29% are oil located on approximately  88,000 net mineral leasehold acres
in twelve  counties in  Oklahoma,  five  counties  in Texas and two  counties in
Arkansas.  Total net daily production from the Mid-Continent  properties for the
month of December  2000 was  approximately  23 million cubic feet of natural gas
production and 980 barrels of oil. Approximately 91% of the Proved Reserves were
classified  Proved  Developed  Reserves as of December 31, 2000.  The  Company's
wholly-owned  subsidiary,  Gruy,  is the operator of 89% or 663 of the 743 wells
located in the Mid-Continent Region.

     The major fields in the  Mid-Continent  Region are the Panoma,  Cumberland,
Walnut Bend and Madill.

     Panoma.  The  Panoma  Properties  currently  consist of  approximately  561
natural gas wells in the West Panhandle,  East Panhandle, and South Erick Fields
along a corridor 66 miles long and 20 miles wide stretching from Beckham County,
Oklahoma  to Gray  County,  Texas.  All wells are less than  2,300 feet deep and
produce natural gas from the Granite Wash and/or Brown Dolomite formations.  For
the month of December 2000, net production was approximately 12.5 MMcf/d.

     Cumberland. The Cumberland Field is located in Bryan and Marshall Counties,
Oklahoma.  It was  discovered in 1940 and is  productive in multiple  reservoirs
from the Goddard  down to the  Arbuckle  formation.  Depths range from 2,000' to
6,800'. Initially, the field produced oil from the Bromide, McLish and Oil Creek
formations.  These zones were unitized in 1964 for waterflood operations,  which
continue today. The "Shallow Gas" zones include the Sycamore,  Woodford, Hunton,
and Viola.  These formations are  predominantly  gas productive and are produced
commingled.   Development  drilling  plans  exist  for  four  additional  proved
undeveloped  locations  to exploit  the shallow  gas on  160-acre  spacing.  The
shallowest  zone in the  field is the  Goddard,  which is a  channel  sand.  The
Company has an interest in a total of 118 wells,  with working interests varying
from 17.2% to 100%.  The Company  operates all but nine of these wells.  For the
month of December 2000, gross production from the field averaged 6,367 Mcf/d and
199 Bbl/d (or 5,090 Mcf/d and 159 Bbl/d net to the Company).

     Walnut Bend. The Walnut Bend Field is located in Cooke County,  Texas.  The
field was  discovered  in the late 1930's and produces oil and gas from numerous
intervals ranging in depth from 2,000' in the Montgomery sands to over 7,000' in
the Ellenburger carbonate. There are currently 104 active producing wells and 30
active injection wells. The Company's working interest ownership in the wells is
approximately  91%. For the month of December 2000,  gross  production  from the
wells  averaged  232  Mcf/d and 846 Bbl/d (or 176 Mcf/d and 642 Bbl/d net to the
Company).

     Madill.  The  Madill  Field is  located  in  Marshall  County  in  Southern
Oklahoma.  The first  production  from this field  occurred in 1906 and produces
primarily gas from various shallow reservoirs,  such as the Sycamore,  Woodford,
Viola and Bromide at depths  ranging from 3,750' to 5,700'.  There are currently
62 active producing wells. The Company's working interest ownership in the wells
varies from 50% to 100%. For the month of December 2000,  gross  production from
the wells  averaged 2,211 Mcf/d and 83 Bbl/d (or 1,437 Mcf/d and 54 Bbl/d net to
the Company).

                                        4
<PAGE>

Permian Basin

     On April 30, 1997 the Company  acquired  from  Burlington,  effective as of
January 1, 1997, certain oil and gas properties  consisting of 25 field areas in
west Texas and 22 field  areas in  southeast  New  Mexico  (the  "Permian  Basin
Properties"),  for a net  purchase  price of $133.8  million  after  adjustments
aggregating $9.7 million.  The primary producing  formations  include the Yates,
Seven Rivers and Queen in Lea and Eddy  Counties,  New Mexico;  the Atoka in the
Brunson  Ranch Field in Loving  County,  Texas;  the  Clearfork in the Westbrook
Field in Mitchell County,  Texas; and the San Andres in the  Levelland/Slaughter
Field in Cochran  County,  Texas.  The Permian  Basin  Properties  include 1,706
producing  oil and gas wells on  approximately  65,000  gross acres  (56,600 net
acres).  One  of  the  Company's  subsidiaries,  Gruy,  serves  as  operator  on
approximately  53% of the  wells on the  Permian  Basin  Properties.  Management
believes  the Permian  Basin  Properties  will  continue to provide  significant
opportunities for exploitation and development opportunities of both oil and gas
through  workovers and  recompletions,  enhanced  recovery  projects and in-fill
drilling.  For example,  the Company has identified more than 100 possible sites
in the  Westbrook  Field (4.7 MMBbl of Proved  Reserves) and  opportunities  for
tertiary  recovery  using carbon  dioxide  injection in the  Levelland-Slaughter
Field (1.2 MMBbl of Proved Reserves).

     According to Ryder Scott and Cawley Gillespie, as of December 31, 2000, the
Permian Basin  Properties  had Proved  Reserves of 13 MMBbl of oil and 84 Bcf of
gas,  or on a Natural Gas  Equivalent  basis,  159 Bcfe.  Ryder Scott and Cawley
Gillespie  further  estimated the PV-10 for the Permian  Basin  Properties to be
$392 million as of December 31, 2000.  Approximately  65% of the Proved Reserves
were  classified  as Proved  Developed  Reserves as of December  31,  2000.  See
"Properties - Oil and Gas Reserves."

     The   major   fields   in   the   Permian   Basin   are   the    Westbrook,
Levelland/Slaughter and Southeast New Mexico.

     Westbrook.  The Westbrook Field covers 45 square miles of the Permian Basin
in Mitchell County,  Texas and produces from the Clearfork  formation at a depth
of approximately 3,200 feet. The Company owns three principal  properties in the
Westbrook Field, being the Southwest  Westbrook Unit, the Morrison "G" Lease and
the North Westbrook Unit.  There are currently 298 active  producing  wells. The
Company's working interest ownership in the wells varies from 0.02% to 100%. For
the month of December 2000, net production from the wells averaged 391 Bbl/d.

     Most of the leases and units in the field had waterflood projects initiated
in the 1960's and those  projects are still  active.  The Company has  continued
waterflood  enhancement  operations  on the  Southwest  Westbrook  Unit  and the
Morrison "G" Lease in 2000.

     Levelland/Slaughter.  The  Levelland and  Slaughter  Fields  consist of 186
wells  located  in  Cochran  County,  Texas  that  produce  from the San  Andres
formation at a depth of 5,000 feet. The Company owns five  principal  properties
in the Levelland and Slaughter  Fields,  being the TLB Unit, the Veal Lease, the
NW Slaughter Unit, the Starnes Lease and the Magnum  Levelland  Unit.  There are
currently 97 active producing wells. The Company's working interest ownership in
the  wells  varies  from 6% to 100%.  For the  month  of  December  2000,  gross
production  from the wells  averaged 503 Mcf/d and 538 Bbl/d (or 75 Mcf/d and 80
Bbl/d net to the Company).

     Discovered  in  the  1930's,   all  five   properties  have  been  actively
waterflooded  since  the  1970's.  While the  projects  are  mature,  additional
drilling and  waterflood  enhancement  opportunities  are  available.  No Proved
Undeveloped  Reserves were assigned by Ryder Scott to either the TLB Unit or the
Veal Lease.  Proved Undeveloped  Reserves were assigned by Ryder Scott to the NW
Slaughter Unit in contemplation of a carbon dioxide  injection  project which is
planned in the future for that  property.  The operator of an adjacent  property
has been  injecting  carbon  dioxide  for a number  of  years  and has  enhanced
production.

     Southeast  New Mexico  Properties.  The  Southeast  New  Mexico  Properties
consist of approximately 430 wells in Lea and Eddy Counties, New Mexico. The Lea
County properties include the Rhodes, Jalmat,  Monument,  Langlie Mattix, Eumont
and Eunice Fields.  The fields produce from the Yates,  Seven Rivers,  Queen and
other formations at depths

                                        5
<PAGE>

     generally  shallower  than  3,000  feet.  Additionally,  the  Company  owns
interests in  approximately  20 wells that produce from the Morrow  formation in
Eddy County,  New Mexico where a current  increased  density program is ongoing.
The Morrow formation is found at  approximately  11,500 feet. We participated in
the drilling of 7 wells in 2000 and has budgeted to drill an additional 11 wells
in 2001.  For the  Southeast  New  Mexico  properties,  approximately  27 proved
undeveloped   locations  have  been  identified  by  the  Company's  third-party
petroleum engineering consultants.

Gulf Coast/Gulf of Mexico

     The Company owns  properties  both onshore Gulf Coast and offshore  Gulf of
Mexico.

Onshore Gulf Coast

     The Company owns various  ownership  interests in five horizontal  wells in
the Mossy Grove  prospect  in Walker  County,  Texas.  The  interests  which the
Company  owns in these three  wells range from a 25% to a 65% working  interest.
The field  produces  from the Glen Rose  formation  at a depth of  approximately
12,000 feet.  The initial  discovery  was completed in July 1998 with the latest
two wells being  drilled in 2000 and 2001.  The Company owns an average of a 25%
working interest in a 36,000 acre lease block surrounding the producing wells. A
sixth well is  currently  being  drilled in which the Company owns a 25% working
interest.  RME  Petroleum,  a  wholly-owned  subsidiary  of  Anadarko  Petroleum
Corporation,  is the operator of the  drilling  phase for this well and owns the
remaining  75%  working  interest.   The  Company  operates  all  of  the  field
production.  For the  month of  December  2000,  gas  production  from the three
producing wells was approximately 3,700 Mcf/d (or 740 Mcf/d net to the Company).
Additional development drilling is planned in this field in future years.

     Other onshore Gulf Coast  properties are located in the Giddings Field, the
First Shot Field and the  Clinton  Field.  Other than the Clinton  Field,  which
produces from a vertical well,  these  properties  are typically  producing from
horizontal legs of vertical wells in these fields.

Offshore Gulf of Mexico

     On March 27,  1998,  the  Company  acquired  approximately  40%  beneficial
ownership  interest in TEL Offshore Trust, a trust created under the laws of the
state of Texas  pursuant to a cash tender offer for an aggregate  purchase price
of approximately $10.4 million.  The principal asset of TEL consists of a 99.99%
interest  in the TEL  Offshore  Trust  partnership.  Chevron  USA Inc.  owns the
remaining .01% interest in the  partnership.  The partnership owns an overriding
royalty interest equivalent to a 25% net profits interest in certain oil and gas
properties  located  offshore  Louisiana.  TEL produced a total of approximately
0.832 Bcfe in calendar 2000.

     The Company entered the Gulf of Mexico as a working interest participant in
new  exploratory  drilling on the shallow water shelf in May 1999. By the end of
2000,  this  program  achieved a result of 16 new  discoveries  in 20  attempts.
Proved  Reserves  have been  assigned in 16  offshore  blocks  representing  the
discoveries.  Seven of these  successes are producing  approximately  25 million
cubic feet of natural gas equivalent per day net to the Company as of the end of
February 2001. Ten  additional new  discoveries  (one of which was discovered in
2001) are scheduled to commence production during the remainder of 2001 and will
add  substantially to existing daily net production rates. The Company currently
owns an interest in over 35 blocks in the Gulf of Mexico  ranging  from 12.5% to
100% with  expectations  of adding to this  lease  inventory  at the March  2001
offshore lease sale. See "Recent  Activities".  The Company plans to participate
in 10-12 new exploratory  offshore drilling projects in 2001. Over 300 blocks of
3-D  seismic  coverage  are  providing  the  basis for new  prospect  generation
internally.  Additionally,  alliances  with other  offshore  operators  provides
access to additional high-quality drilling opportunities.

     The Company has  received an  engineering  evaluation  from Ryder Scott and
DeGoyler and MacNaughton ("D&M"), independent petroleum engineers engaged by the
Company to evaluate the Company's properties, on the net reserves in the Gulf of
Mexico.  According to Ryder Scott and D&M, as of December 31, 2000,  the Gulf of
Mexico  properties had Proved Reserves of 1.9 MMBbl of oil and 31 Bcf of natural
gas, or on a Natural Gas Equivalent  basis, 42 Bcfe. Ryder Scott and D&M further
estimated  the PV-10 for the Gulf of Mexico  properties to be $203 million as of
December 31, 2000.  Approximately 73% of the estimated  reserves are natural gas
and 27% are oil located on  approximately  430,040 net mineral  leasehold acres.
Total net daily  production from the Gulf of Mexico  properties for the month of
December 2000 was  approximately 13 million cubic feet of natural gas production
and 189 barrels of oil.

                                        6
<PAGE>

Gas Processing Plants

McLean Plant

     On January 1, 1997,  the Company  complemented  its Panoma  acquisition  by
purchasing for $2.5 million a 50% ownership interest in the McLean Gas Plant and
a related 22 mile  products  pipeline.  This plant is a modern  cryogenic  plant
utilizing  approximately  2,000  horsepower of high speed  compression and a gas
processing  capacity of  approximately  23 million  cubic feet per day.  For the
month of December 2000, throughput of the plant averaged 13.3 million cubic feet
per day with processed liquids of 867 barrels per day.

Madill Plant

     On December 1, 1999, the Company  acquired the Madill Gas Processing  Plant
and associated  gathering system assets from Dynegy Midstream Services,  Limited
Partnership,  a  wholly-owned  subsidiary of Dynegy Inc for  approximately  $8.4
million.  The gas  processing  plant and  associated  facilities  are located in
Marshall and Bryan Counties,  Oklahoma and were acquired in conjunction with the
Company's 50% partner, Carrera Gas Gathering Co., L.L.C., of Tulsa, Oklahoma who
subsequently  paid 50% of the purchase price. The acquisition  includes over 130
miles  of gas  gathering  pipelines.  This  modern  cryogenic  plant  has  3,350
horsepower  of  high  speed  compression  and  has gas  processing  capacity  of
approximately  18 million  cubic feet per day.  For the month of December  2000,
throughput of the plant  averaged 11.9 million cubic feet per day of natural gas
with processed  liquids of 680 barrels per day. See "Gathering and Processing of
Gas."

Walker Creek Plant

     In  conjunction  with the  Vastar  acquisition,  the  Company  acquired  an
approximate  59% ownership  interest and became the operator of the Walker Creek
Plant and  associated  gathering  system.  This facility is located in southwest
Arkansas in Lafayette and Columbia counties.  This propane  refrigeration  plant
utilizes  3,160  horsepower  of  leased  compression  and  has a gas  processing
capacity  of 12 million  cubic  feet per day.  For the month of  December  2000,
throughput of the plant averaged 8.6 MMcf/d with processed liquids of 411 Bbl/d.

Development and Exploration Activities

Overview

     The  Company  presently  intends  to  continue  to  focus  its  efforts  on
exploration, property acquisitions and its substantial inventory of exploitation
and development drilling projects.

     The Company  seeks to minimize  its overhead  and capital  expenditures  by
subcontracting  the drilling,  redrilling  and workover of wells to  independent
drilling  contractors and by outsourcing  other services.  The Company typically
compensates its drilling  subcontractors on a turnkey (fixed price),  footage or
day-rate  basis  depending  on  the  Company's   assessment  of  risk  and  cost
considerations on each individual project.

Development Drilling

     The Company's  development  strategy  focuses on  maximizing  the value and
productivity  of its oil and gas asset base  through  development  drilling  and
enhanced recovery projects.  The Company has budgeted  approximately $51 million
for  exploitation  and development  activities for 2001 with $28 million of such
budget allocated to the Company's proved undeveloped reserves. The Company spent
$4.1 million, $1.4 million and $7.9 million, respectively, developing its proved
undeveloped  reserves for the years ended 2000,  1999 and 1998.  The Company has
identified 237  development  drilling  locations  (including both production and
injection   wells)  on  its  properties  to  which  proved  reserves  have  been
attributed. In exploiting its producing properties,  the Company relies upon its
in-house technical staff of petroleum  engineering and geological  professionals
and utilizes the services of outside consultants on a selective basis.

                                        7
<PAGE>

     Mid-Continent Region. The Company believes that developmental  drilling can
continue to enhance the value of the Panoma  Properties,  which produce from the
Brown  Dolomite and Granite Wash  formations in the Texas  Panhandle and western
Oklahoma.  The easternmost  fields are developed on 160 acre spacing because the
original spacing of 640 acres proved  inadequate to drain reserves  efficiently.
In-fill  development  has been underway in the fields with 101 wells having been
drilled and completed during the last four years. The westernmost  field has now
been developed with 320 acre spacing, and future develop drilling will bring the
spacing down to a more efficient 160 acres per well.

     The  Cumberland  Field was discovered in 1940 and is productive in multiple
reservoirs  from the Goddard down to the Arbuckle  formation.  Depths range from
2,000' to 6,800'. Initially, the field produced oil from the Bromide, McLish and
Oil  Creek  formations.  These  zones  were  unitized  in  1964  for  waterflood
operations,  which continue today. The "Shallow Gas" zones include the Sycamore,
Woodford,  Goddard,  Hunton,  and Viola.  These formations are predominantly gas
productive  and  are  produced  commingled.  The  Company  has  identified  four
locations  in which  additional  wells  could be drilled  in proved  undeveloped
reserves to complete  development  of the shallow gas on 160-acre  spacing.  One
well was drilled and several recompletions were successfully  performed in 2000.
Additional drilling and recompletions are budgeted in 2001.

     Additional Mid-Continent development,  drilling and recompletion activities
will focus on the  Walnut  Bend Field in Cooke  County,  Texas and the  Morrison
Ranch Field in Roberts County, Texas.

     Permian Basin Properties.  In evaluating the Permian Basin Properties,  the
Company has  identified  over 200 drilling  locations  including  production and
injection  wells.  Primary  development  focus will be on the increased  density
drilling opportunities.  Numerous workovers, recompletions and development wells
are targeted for the shallow gas properties in Lea County,  New Mexico.  Further
development of the Westbrook Field in Mitchell County,  Texas began in 2000 when
seven producing wells and five injection  wells were drilled.  Approximately  29
wells are for 2001.

     Onshore Gulf Coast.  The Company owns various  ownership  interests in five
horizontal  wells in the Mossy  Grove  prospect  in Walker  County,  Texas.  The
interests  which the Company owns in these three wells range from a 25% to a 65%
working interest.  The field produces from the Glen Rose formation at a depth of
approximately 12,000 feet. The initial discovery was completed in July 1998 with
the latest two wells being drilled in 2000 and 2001. The Company owns an average
of a 25% working interest in a 36,000 acre lease block surrounding the producing
wells.  A sixth well is currently  being drilled in which the Company owns a 25%
working interest. RME Petroleum, a wholly-owned subsidiary of Anadarko Petroleum
Corporation,  is the operator of the  drilling  phase for this well and owns the
remaining  75%  working  interest.   The  Company  operates  all  of  the  field
production.  For the  month of  December  2000,  gas  production  from the three
producing wells was approximately 3,700 Mcf/d (or 740 Mcf/d net to the Company).
Additional development drilling is planned in this field in future years.

Exploratory Drilling

     The Company  spent $40 million of its $60 million  2000  capital  budget on
exploratory  drilling and related land and geophysical  costs.  Sixteen offshore
exploratory  wells were drilled in 2000 of which 15 are commercially  productive
wells providing the Company with a 94% success rate. The most significant change
in strategy  occurred  when the Company  entered the Gulf of Mexico as a working
interest  owner in new  exploratory  drilling on the shallow  water shelf in May
1999.  This new program  yielded 16 new discoveries in 20 attempts by the end of
2000  and as the  Proved  Reserves  associated  with  these 16  discoveries  are
developed,   they  are  projected  to  add  significant  cash  flow.  Currently,
production from seven new offshore blocks is approximately 25 MMcfe/d net to the
Company as of the end of February 2001. Ten new platforms  scheduled to commence
production in 2001 should add substantially to these levels. The Company owns an
interest  ranging  from 12.5% to 100% in over 40 offshore  blocks and expects to
add  significantly to the number of OCS blocks in 2001. See "Recent Events".  An
aggressive drilling program will continue in 2001.

     The onshore exploration  program remains active.  Drilling in New Mexico in
2000 and early  2001 has  resulted  in six new  Morrow  gas wells  with  working
interests ranging from 50% to 90%. Per well production is expected to range from
1 million to 8 million cubic feet of natural gas per day. A new shallow zone oil
discovery  was  producing  over 70 Bbl/d (29 Bbl/d net to the  Company) in March
2001. Eight proved undeveloped  locations remain to be drilled in New Mexico and
over 30 drill sites are identified as a result of activity in New Mexico.

                                        8
<PAGE>

     In West Texas, 12 consecutive  producing wells have been drilled during the
past  year  in the  Goldsmith  Area.  Occidental  Petroleum  Corporation  is the
operator and the Company owns a 25% - 35% working interest in a 30,000 acre area
of mutual  interest.  The latest well tested over 350 Bbl/d (65 Bbl/d net to the
Company).  Ten proved  undeveloped  locations  remain to be drilled  and over 20
drill sites are identified as a result of activity in the Goldsmith Area.

     A new discovery in the Texas Panhandle area, new prospects on the Texas and
Louisiana  Gulf  Coast area and a  continuing  offshore  Gulf of Mexico  program
should  provide  ample  opportunity  to grow  reserves and  production in future
years.

Gathering and Processing of Gas

     Hunter Gas Gathering,  Inc. and Bluebird  Energy,  Inc., both  wholly-owned
subsidiaries  of the  Company,  own  three  gas  gathering  systems  located  in
Oklahoma,  Texas and  Arkansas,  none of which are subject to  regulation by the
Federal Energy Regulatory Commission ("FERC"),  and ownership interests in three
gas processing plants. Gruy operates all of the gas gathering systems and one of
the gas processing plants.

     Generally,  the gathering systems transport the natural gas from wells to a
common point where it is dehydrated prior to redelivery to downstream pipelines.
In managing its gas  gathering  systems,  the Company has  emphasized  operating
efficiency  and  overhead   management  and  introduced  a  program  which  ties
throughput costs to volume transported rather than to compression capacity.  The
Company  believes that its focus on  volume-based  pricing reduces the potential
financial impact of a decline in actual throughput.  Since compression costs are
not fixed, but are tied to volumes transported,  the compression operator has an
incentive to ensure that as much volume is being  transported  as possible.  The
lower the volume transported, the lower the fee to the compression operator.

     The Panoma  system,  the largest of the Company's  gas  gathering  systems,
consists of approximately 446 miles of pipeline. The main trunklines run east to
west for  approximately  66 miles with the east end starting in Beckham  County,
Oklahoma and the west end starting in Gray County,  Texas. At year end 2000, gas
throughput for the Panoma gas gathering system was  approximately  14.8 MMcf per
day. The Panoma gas  gathering  system is  connected  to a third party  "header"
system which provides access to all major  interstate  pipelines in the area via
seven pipeline interconnects serving Midwestern, Western and Oklahoma intrastate
markets. The Company,  which operates approximately 500 of the approximately 585
wells connected to the Panoma system,  is also actively seeking to add new wells
to such system through acquisition, development or arrangements with third party
producers.

     Effective  January 1, 1997,  the Company  purchased  for $2.5 million a 50%
ownership  interest in the McLean Gas Plant, a gas processing  facility  located
adjacent  to the  Company's  Panoma gas  gathering  system.  The  purchase  also
included a 22 mile products  pipeline  between the McLean Gas Plant and the Koch
Pipeline at Lefors,  Texas and all gas and product purchase and sales agreements
related to the plant.  The McLean Gas Plant is a modern cryogenic gas processing
plant with a throughput capacity of 23.0 MMcf per day. For the month of December
2000,  throughput was approximately  13.3 MMcf per day. The Company acquired its
50% ownership interest in the plant from Carrera Gas Company, L.L.C. ("Carrera")
of Tulsa,  Oklahoma,  which owns the remaining 50% of the plant and operates the
facility.

     On December 1, 1999, the Company  acquired the Madill Gas Processing  Plant
and associated  gathering system assets from Dynegy Midstream Services,  Limited
Partnership,  a wholly-owned  subsidiary of Dynegy Inc. The gas processing plant
and associated  facilities are located in Marshall and Bryan Counties,  Oklahoma
and were acquired in conjunction  with the Company's 50% partner,  Carrera.  The
acquisition  includes  over 130 miles of gas  gathering  pipelines.  This modern
cryogenic  plant has 3,350  horsepower  of high  speed  compression  and has gas
processing  capacity of  approximately  18 million  cubic feet per day.  For the
month of December 2000,  throughput of the plant was approximately  11.9 million
cubic feet per day of natural gas with processed liquids of 680 barrels per day.

                                        9
<PAGE>

     In  conjunction   with  the  Vastar   acquisition,   the  Company  acquired
approximately 59% ownership interest and became the operator of the Walker Creek
Plant and associated gathering system. On May 24, 2000, the Company sold a 44.2%
interest in the Walker Creek Plant to Mallard  Hunter L.P.,  the  Company's  new
partnership  discussed in Recent Activities - Strategic Alliance on page 2. This
facility is located in southwest  Arkansas in Lafayette  and Columbia  counties.
This propane  refrigeration  plant utilizes 3,160 horsepower leased  compression
and has a gas  processing  capacity  of 12 million  cubic feet per day.  For the
month of December  2000,  throughput of the plant was  approximately  8.6 MMcf/d
with processed liquids of 411 Bbl/d.

Marketing of Production

     The Company  markets all of its gas  production as well as gas it purchases
from third  parties to gas marketing  firms or end-users  either on (i) the spot
market under  contracts of less than one year at  prevailing  spot market prices
(approximately  62% of our  volume) or (ii) at market  responsive  prices  under
multi-year  contracts  (approximately 38% of our volume).  Marketing gas for its
own  account  exposes the Company to the  attendant  commodities  risk which the
Company  attempts to mitigate  through  various  financial  hedges.  The Company
normally  sells its own oil under  month-to-month  contracts  with a variety  of
crude oil purchasers.  Oil is usually sold for the Company's own account through
the services of Enmark Services,  a marketing agent in Dallas,  Texas. While the
Company has historically  been able to sell oil above posted prices,  it is also
exposed to the  commodities  risk  inherent in  short-term  contracts  which the
Company attempts to mitigate through various financial hedges.  For a discussion
of the Company's hedging activities,  see "Management's  Discussion and Analysis
of  Financial  Condition  and  Results of  Operations  -  Liquidity  and Capital
Resources  -  Hedging  Activity"  and  Note  13 to  the  Company's  Consolidated
Financial Statements.

     In December  1997,  Hunter Gas  Gathering,  Inc.  acquired a thirty percent
(30%)  membership  interest in NGTS,  a subsidiary  of Natural Gas  Transmission
Services,  Inc. ("NGTS, Inc."). NGTS assumed all of NGTS Inc.'s operations as of
December 1, 1997. The Company acquired its interest in NGTS for consideration of
$4.35 million.

     NGTS is a  Dallas-based  natural gas  marketing  and trading  company  with
operations  concentrated  in the western  two-thirds  of the country.  In fiscal
2000,  NGTS reported  total  revenues of  approximately  $522  million.  NGTS is
presently marketing approximately 375 million cubic feet of natural gas per day.
In fiscal 1999, NGTS reported total revenues of approximately $277 million.  For
1998, the Company and its gas gathering subsidiary,  Hunter Gas Gathering, Inc.,
dedicated substantially all of its natural gas production to NGTS for marketing.
As of December  31,  2000,  NGTS  marketed  approximately  30% of the  Company's
natural gas under short term contracts.  The balance of the Company's production
is marketed through other marketing companies or gatherer/processors.

     The market for oil and  natural  gas  produced  by the  Company  depends on
factors  beyond its control,  including  the extent of domestic  production  and
imports of oil and  natural  gas,  the  proximity  and  capacity  of natural gas
pipelines  and other  transportation  facilities,  weather,  demand  for oil and
natural gas, the  marketing  of  competitive  fuels and the effects of state and
federal  regulation.  The oil and natural gas industry  also competes with other
industries  in  supplying  the  energy  and  fuel  requirements  of  industrial,
commercial and individual consumers.

Petroleum Management and Consulting Services

     The Company acquired Gruy in December 1995. Gruy, which conducts operations
for both the Company and third parties,  has over a 44-year  history of managing
properties for financial institutions,  bankruptcy trustees, estates, individual
investors, trusts and independent oil and gas companies. Gruy provides drilling,
completion and other well-site  services;  advice  regarding  environmental  and
other regulatory compliance;  receipt and disbursement functions, expert witness
testimony and other managerial services and petroleum engineering services. Gruy
manages,  operates and provides  consulting  services on oil and gas properties,
gathering systems and processing plants located in Texas, Oklahoma, Mississippi,
Louisiana,  New  Mexico  and  Kansas.  Gruy  is an  important  component  of the
Company's acquisition program. As the operator of wells for third parties and as
a  provider  of  consulting  services  for the  energy  industry,  Gruy is often
uniquely able to identify attractive acquisition opportunities.

                                       10
<PAGE>

Competition

     The oil and gas industry is highly competitive.  Competitors of the Company
include  major  oil  companies,  other  independent  oil and gas  concerns,  and
individual  producers and operators,  many of which have  substantially  greater
financial  resources and larger staffs and facilities than those of the Company.
In addition, the Company frequently encounters competition in the acquisition of
oil and gas  properties  and gas gathering  systems,  and in its  management and
consulting business.  The principal means of such competition are the amount and
terms of the consideration offered. The principal means of such competition with
respect  to the sale of oil and gas  production  are  product  availability  and
price. The price at which the Company's products may be sold will continue to be
affected by a number of factors,  including the price of alternate fuels such as
oil,  natural gas, nuclear power,  hydroelectric  power and coal and competition
among various gas producers and marketers.

Regulation

       General Federal and State Regulation

     There have been,  and continue to be,  numerous  federal and state laws and
regulations  governing  the oil and gas  industry  that  are  often  changed  in
response to the current political or economic environment.  Compliance with this
regulatory  burden is often  difficult  and  costly  and may  carry  substantial
penalties for  noncompliance.  The following are some specific  regulations that
may affect the Company. The Company cannot predict the impact of these or future
legislative or regulatory initiatives.

       Regulation of Natural Gas and Oil Exploration and Production

     The Company's  operations are subject to various types of regulation at the
federal,  state and local levels. Such regulation includes requiring permits for
drilling wells,  maintaining  bonding  requirements in order to drill or operate
wells and  regulating  the location of wells,  the method of drilling and casing
wells,  the  surface  use and  restoration  of  properties  upon which wells are
drilled, the plugging and abandoning of wells and the disposal of fluids used in
connection with operations. The Company's operations are also subject to various
conservation  laws and regulations.  These include the regulation of the size of
drilling and spacing units or proration units and the density of wells which may
be drilled in and the  unitization  or  pooling  of oil and gas  properties.  In
addition, state conservation laws establish maximum rates of production from oil
and gas  wells,  generally  prohibit  the  venting  or flaring of gas and impose
certain requirements regarding the ratability of production. The effect of these
regulations may limit the amount of oil and gas the Company can produce from its
wells and may limit the number of wells or the  locations  at which the  Company
can drill.  The  regulatory  burden on the oil and gas  industry  increases  the
Company's costs of doing business and, consequently,  affects its profitability.
Inasmuch  as such laws and  regulations  are  frequently  expanded,  amended and
reinterpreted,  the  Company is unable to predict  the future  cost or impact of
complying with such regulations.

       Federal Regulation of Sales Prices and Transportation

     Currently,  there are no  federal,  state or local laws that  regulate  the
price for sales of natural gas,  NGLs,  crude oil or  condensate by the Company.
However,  the rates charged and terms and  conditions for the movement of gas in
interstate  commerce  through certain  intrastate  pipelines and production area
hubs are  subject  to  regulation  under  the  Natural  Gas  Policy  Act of 1978
("NGPA").  Pipeline and hub  construction  activities  are, to a limited extent,
also subject to  regulations  under the Natural Gas Act of 1938  ("NGA").  While
these controls do not apply directly to the Company, their effect on natural gas
markets can be significant in terms of  competition  and cost of  transportation
services. Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress,  FERC,  state  regulatory
bodies and the courts.  The Company cannot predict when or if any such proposals
might become  effective and their effect,  if any, on the Company's  operations.
Historically,  the natural gas industry has been heavily  regulated;  therefore,
there is no  assurance  that the less  stringent  regulatory  approach  recently
pursued by FERC,  Congress and the states will  continue  indefinitely  into the
future.

                                       11
<PAGE>

       Gathering Regulations

     State regulation of gathering facilities generally includes various safety,
environmental and, in some circumstances,  nondiscriminatory  take requirements.
Such regulation has not generally been applied against gatherers of natural gas,
although  natural gas gathering may receive greater  regulatory  scrutiny in the
future.  Federal,  State or Indian Leases The  Company's  operations on federal,
state or  Indian  oil and gas  leases  are  subject  to  numerous  restrictions,
including nondiscrimination statutes. Such operations must be conducted pursuant
to certain on-site  security  regulations  and other permits and  authorizations
issued by the Bureau of Land Management,  Minerals  Management Service and other
agencies.

       Environmental Regulation

     The  Company's  exploration,  development,  and  production of oil and gas,
including its operation of saltwater  injection and disposal wells,  are subject
to various federal,  state and local  environmental  laws and regulations.  Such
laws and regulations can increase the costs of planning,  designing,  installing
and operating oil and gas wells. The Company's  domestic  activities are subject
to a variety of environmental  laws and  regulations,  including but not limited
to, the Oil  Pollution  Act of 1990  ("OPA"),  the Clean Water Act ("CWA"),  the
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"),
the Resource Conservation and Recovery Act ("RCRA"),  the Clean Air Act ("CAA"),
and  the  Safe  Drinking  Water  Act  ("SDWA"),  as well  as  state  regulations
promulgated  under  comparable  state  statutes.  The Company also is subject to
regulations  governing the handling,  transportation,  storage,  and disposal of
naturally  occurring  radioactive  materials  that are  found in its oil and gas
operations.   Civil  and  criminal  fines  and  penalties  may  be  imposed  for
non-compliance  with these  environmental  laws and  regulations.  Additionally,
these  laws  and  regulations  require  the  acquisition  of  permits  or  other
governmental  authorizations  before undertaking  certain  activities,  limit or
prohibit  other  activities  because of protected  areas or species,  and impose
substantial liabilities for cleanup of pollution.

     Under the OPA, a release of oil into water or other areas designated by the
statute  could  result in the Company  being held  responsible  for the costs of
remediating such a release,  certain OPA specified damages, and natural resource
damages.  The extent of that liability  could be extensive,  as set forth in the
statute,  depending  on the nature of the  release.  A release of oil in harmful
quantities or other  materials  into water or other  specified  areas could also
result in the  Company  being  held  responsible  under the CWA for the costs of
remediation, and civil and criminal fines and penalties.

     CERCLA and comparable state statutes,  also known as "Superfund"  laws, can
impose joint and several and retroactive  liability,  without regard to fault or
the  legality of the  original  conduct,  on certain  classes of persons for the
release of a "hazardous  substance" into the environment.  In practice,  cleanup
costs are usually  allocated  among  various  responsible  parties.  Potentially
liable parties include site owners or operators,  past owners or operators under
certain conditions,  and entities that arrange for the disposal or treatment of,
or  transport  hazardous  substances  found at the  site.  Although  CERCLA,  as
amended,  currently exempts petroleum,  including but not limited to, crude oil,
gas and natural gas liquids  from the  definition  of hazardous  substance,  the
Company's operations may involve the use or handling of other materials that may
be classified as hazardous substances under CERCLA. Furthermore, there can be no
assurance that the exemption will be preserved in future  amendments of the act,
if any.

     RCRA and comparable state and local  requirements  impose standards for the
management,  including  treatment,  storage,  and disposal of both hazardous and
nonhazardous  solid wastes.  The Company  generates  hazardous and  nonhazardous
solid  waste in  connection  with its  routine  operations.  From  time to time,
proposals  have been made that  would  reclassify  certain  oil and gas  wastes,
including wastes generated during drilling,  production and pipeline operations,
as "hazardous  wastes" under RCRA which would make such solid wastes  subject to
much more stringent handling,  transportation,  storage,  disposal, and clean-up
requirements.  This development could have a significant impact on the Company's
operating  costs.  While state laws vary on this  issue,  state  initiatives  to
further regulate oil and gas wastes could have a similar impact.

                                       12
<PAGE>

     Because  oil  and  gas  exploration  and  production,  and  possibly  other
activities,  have been conducted at some of the Company's properties by previous
owners and  operators,  materials  from these  operations  remain on some of the
properties and in some instances require  remediation.  In addition,  in certain
instances  the Company has agreed to indemnify  sellers of producing  properties
from whom the Company has acquired  reserves  against  certain  liabilities  for
environmental claims associated with such properties. While the Company does not
believe that costs to be incurred by the Company for compliance and  remediating
previously or currently owned or operated properties will be material, there can
be no guarantee that such costs will not result in material expenditures.

     Additionally,   in  the  course  of  the  Company's  routine  oil  and  gas
operations,  surface spills and leaks,  including  casing leaks, of oil or other
materials   occur,   and  the  Company  incurs  costs  for  waste  handling  and
environmental compliance.  Moreover, the Company is able to control directly the
operations  of only those  wells for which it acts as the  operator.  Management
believes  that  the  Company  is  in  substantial   compliance  with  applicable
environmental laws and regulations.

     It is not anticipated  that the Company will be required in the near future
to  expend   amounts  that  are  material  in  relation  to  its  total  capital
expenditures  program  by  reason of  environmental  laws and  regulations,  but
inasmuch as such laws and  regulations  are frequently  changed,  the Company is
unable to predict the  ultimate  cost of  compliance.  There can be no assurance
that more stringent laws and regulations  protecting the environment will not be
adopted or that the  Company  will not  otherwise  incur  material  expenses  in
connection with environmental laws and regulations in the future.

Employees

     At December  31, 2000,  the Company had 95 full-time  employees of which 29
were management, 33 were administrative and 33 were field employees. None of the
Company's  employees  are  represented  by a  union.  Management  considers  its
relations with employees to be good.

Facilities

     The Company  occupies  approximately  23,386 square feet of office space at
600 East Las Colinas Boulevard,  Suite 1100,  Irving,  Texas, under a lease that
expires in October 2004. The Company owns field offices and production  yards in
Shamrock and Gainesville,  Texas and Taylor,  Arkansas.  The Company also leases
field production  offices in Midland and Abilene,  Texas,  Hobbs, New Mexico and
Oklahoma City, Oklahoma.

Risk Factors

Risks Related to Substantial Leverage
-------------------------------------

We have a significant amount of debt

     We are highly leveraged,  with outstanding  long-term debt of approximately
$191 million  compared to  stockholders'  equity of $93.4 million as of December
31, 2000. Our level of indebtedness  affects our future  operations.  Because we
must  dedicate a  substantial  portion of our cash flow from  operations  to the
payment  of  interest  on our  debt,  the cash flow is not  available  for other
purposes.  The covenants  contained in our credit facilities  require us to meet
certain  financial tests and limit our ability to borrow  additional funds or to
acquire or dispose of assets.  Also, our ability to obtain additional  financing
in the future may be impaired by our  substantial  leverage.  Additionally,  the
senior (as opposed to subordinated) status of our 10% Senior Notes due 2007, our
high debt to equity ratio, and the pledge of substantially  all of our assets as
collateral for our primary credit  facility  will, for the  foreseeable  future,
make it difficult for us to obtain  financing on an unsecured basis or to obtain
secured   financing   other   than   certain   "purchase   money"   indebtedness
collateralized by the acquired assets.

                                       13
<PAGE>

To service our indebtedness, we will require a significant amount of cash

     While we  reported  operating  profits for fiscal  years 2000 and 1999,  we
reported an operating  loss for fiscal 1998, and at December 31, 2000, we had an
accumulated  deficit  of  $50.2  million.  Our  ability  to meet  our  financial
covenants and to make scheduled  payments of principal and interest to repay our
indebtedness  depends  upon our  operating  results  and our  ability  to obtain
financing.  However,  we cannot  be  certain  that our  business  will  generate
sufficient  cash  flow  from  operations  or that  future  bank  credit  will be
available in an amount  sufficient to enable us to service our  indebtedness  or
make necessary capital expenditures. In such event, we would need to obtain such
financing from the sale of equity  securities,  other debt financing or the sale
of certain of the  Company's  properties.  We cannot  predict  whether  any such
financing  will be  available on terms  acceptable  to us. If we are not able to
secure such financing,  we may not be able to continue to implement our business
strategy.

Despite our current indebtedness levels, we still may be able to incur more debt

     Our primary  credit  facility  limits our  borrowings  to a borrowing  base
amount determined by the lenders, in their sole discretion, based upon a variety
of factors,  including the amount of indebtedness  that our oil and gas reserves
and other assets can adequately  support.  As of December 31, 2000, we had $22.5
million of borrowing  available  under the borrowing base for our current credit
facility.  Our subsidiary  Bluebird  Energy,  Inc. has a non-recourse  revolving
credit  facility  which, as of December 31, 2000, had $21.4 million of borrowing
available. A significant decline in oil or gas prices below their current levels
could  materially  adversely  affect the  availability of funds under our credit
facility.

We must maintain certain financial ratios

     Our primary credit facility also requires us to satisfy  certain  financial
ratios in the future.  One covenant  requires that we maintain a ratio of funded
indebtedness divided by the sum of funded indebtedness plus equity (the "Debt to
Capitalization  Ratio") of not more than 0.80 to 1.0. At December 31,  2000,  we
had a Debt to Capitalization  Ratio of 0.58 to 1.0. Another covenant requires us
to maintain a ratio of  Consolidated  EBITDA to Interest  Expense (as defined in
our primary  credit  facility  agreements)  of not less than 2.00 to 1.0 for the
calendar  quarters ending  September 30, 2000 and thereafter.  We had a ratio of
Consolidated  EBITDA to Interest Expense of 3.99 to 1.0 as of December 31, 2000.
The  Consolidated  EBITDA to Interest Expense ratio is very sensitive to oil and
gas  price  levels,  and a  lowering  of  product  prices  in the  future  might
jeopardize  our  compliance  with  this  ratio.   We  are  considering   several
alternatives  to reduce  this risk,  including  the  acquisition  or drilling of
higher cash flow producing  properties (shorter reserve life) to somewhat offset
our long-lived reserve base or monetizing certain of our non-strategic assets.

     If we fail to satisfy these  covenants or any of the other covenants in our
credit facilities,  that failure would constitute an event of default thereunder
and, subject to certain grace periods,  may permit the lenders to accelerate the
indebtedness  then outstanding  under the applicable  credit facility and demand
immediate repayment thereof.

Our Business Is Dependent on Conditions in the Oil and Gas Industry
-------------------------------------------------------------------

     Our  revenues,  profitability  and the  carrying  value  of our oil and gas
properties depend  substantially  upon prevailing prices of, and demand for, oil
and gas and the costs of acquiring,  finding, developing and producing reserves.
Oil and gas prices also substantially affect our ability to maintain or increase
our borrowing capacity,  to repay current or future indebtedness,  and to obtain
additional  capital on attractive terms.  Historically,  the markets for oil and
gas have been  volatile and are likely to continue to be volatile in the future.
Prices for oil and gas fluctuate widely in response to:

     o relatively minor changes in the supply of, and demand for, oil and gas;
     o market uncertainty; and
     o a variety of additional factors, all of which are beyond our control.

                                       14
<PAGE>

     These factors include domestic and foreign political conditions,  the price
and availability of domestic and imported oil and gas, the level of consumer and
industrial demand, weather, domestic and foreign government relations, the price
and  availability  of alternative  fuels and overall  economic  conditions.  Our
production is  predominantly  weighted  toward gas, making our earnings and cash
flow more sensitive to gas price  fluctuations.  Also, our ability to market our
production  depends in part upon the  availability,  proximity  and  capacity of
gathering systems,  pipelines and processing  facilities.  Volatility in oil and
gas prices  could  affect our  ability to market  our  production  through  such
systems,  pipelines or facilities.  Currently, we sell substantially all our gas
production  to gas  marketing  firms or end users either on the spot market on a
month-to-month  basis at  prevailing  spot  market  prices  or  under  long-term
contracts  based on current spot market  prices.  An affiliate of ONEOK Inc. has
the right to market the undedicated natural gas we sell in the state of Oklahoma
until  February  2004 or such  earlier date as ONEOK  affiliates  cease to own a
specified  percentage of our equity securities.  At December 31, 2000, ONEOK was
marketing production from 38 wells for a total of 2,634 Mcf/d.

     Under the full cost accounting  method,  we are required to take a non-cash
charge against  earnings if capitalized  costs of  acquisition,  exploration and
development  (net of depletion,  depreciation and  amortization),  less deferred
income taxes,  exceed the present value of our proved  reserves and the lower of
cost or fair value of unproved  properties after income tax effects. As a result
of the severe  decline in oil and gas prices in 1998,  we  recognized a non-cash
impairment  of oil and gas  properties  of $42.7  million at  December  31, 1998
pursuant to such "ceiling"  test in the full cost method of accounting.  Certain
subsequent  improvements in pricing  reduced the amount of such charge.  Without
the benefit of these pricing improvements,  we would have incurred an impairment
of $81.2 million.  Once incurred,  a write-down of oil and gas properties is not
reversible at a later date even if oil and gas prices increase.

You Should Not Place Undue Reliance on Our Reserve Data Because
  They Are Estimates
----------------------------------------------------------------

     This annual report  contains  estimates of our oil and gas reserves and the
future  net cash  flows from those  reserves  that were  prepared  or audited by
independent petroleum consultants.  There are numerous uncertainties inherent in
estimating quantities of proved reserves of oil and gas and in projecting future
rates of production and the timing of development  expenditures,  including many
factors beyond our control.  The estimates in this annual report rely on various
assumptions,  including,  for example,  constant  oil and gas prices,  operating
expenses,  capital  expenditures and the availability of funds, and,  therefore,
are inherently  imprecise  indications  of future net cash flows.  Actual future
production, cash flows, taxes, operating expenses,  development expenditures and
quantities of recoverable oil and gas reserves may vary substantially from those
assumed in the estimates.  Any significant  variance in these  assumptions could
materially affect the estimated quantity and value of reserves. Additionally, we
may have to revise  our  reserves  based  upon  actual  production  performance,
results of future development and exploration, prevailing oil and gas prices and
other factors, many of which are beyond our control.

     You should not construe the present value of proved reserves referred to in
this annual report as the current market value of the estimated  proved reserves
of oil and gas attributable to our properties. In accordance with Securities and
Exchange Commission requirements,  we have based the estimated discounted future
net cash flows from  proved  reserves  on prices and costs as of the date of the
estimate,  whereas  actual future prices and costs may vary  significantly.  The
following factors may also affect actual future net cash flows:

     o the timing of both production and related expenses;
     o changes in consumption levels; and
     o governmental regulations or taxation.

     In addition,  the  calculation  of the present value of the future net cash
flows using a 10% discount as required by the Securities and Exchange Commission
is not necessarily the most appropriate discount rate based on interest rates in
effect from time to time and risks  associated  with our reserves or the oil and
gas  industry  in  general.  Furthermore,  we may need to  revise  our  reserves
downward or upward based upon actual production,  results of future development,
supply  and  demand  for oil and gas,  prevailing  oil and gas  prices and other
factors.

                                       15
<PAGE>

Maintaining Reserves And Revenues in The Future Depends on Successful
  Exploration And Development
-----------------------------------------------------------------------

     Our future success  depends upon our ability to find or acquire  additional
oil and gas reserves that are economically  recoverable.  Unless we successfully
explore or develop or acquire properties containing proved reserves,  our proved
reserves  will  generally  decline as we produce  them.  The decline rate varies
depending upon reservoir  characteristics and other factors.  Our future oil and
gas  reserves  and  production,  and,  therefore,  cash flow and income,  depend
greatly upon our success in  exploiting  our current  reserves and  acquiring or
finding  additional  reserves.  We cannot  assure that our  planned  development
projects  and  acquisition  activities  will  result in  significant  additional
reserves or that we will successfully drill productive wells at economic returns
to replace our current and future production.

Our Acquisitions Involve Certain Risks
---------------------------------------

     We have  grown  primarily  through  acquisitions  and  intend  to  continue
acquiring oil and gas  properties in the future.  Although we review and analyze
the properties that we acquire,  such reviews are subject to  uncertainties.  It
generally is not possible to review in detail every individual property involved
in an  acquisition.  Ordinarily,  we  focus  our  review  on  the  higher-valued
properties.  However,  even a detailed  review of all properties and records may
not reveal  existing or  potential  problems.  Economics  dictate that we cannot
become  sufficiently  familiar  with all the  properties  to assess  fully their
deficiencies  and  capabilities.  We do not always conduct  inspections on every
well. Even when we do inspect a specific well, we cannot always detect potential
problems, such as mechanical integrity of equipment and environmental conditions
that may require significant remedial expenditures.

     We have begun to focus our  acquisition  efforts on larger  packages of oil
and gas  properties.  Acquisitions  of larger oil and gas properties may involve
substantially  higher costs and may pose additional issues regarding  operations
and management.  We cannot assure that we will be able to successfully integrate
all of the oil and gas  properties  that we acquire into our  operations or will
achieve desired profitability objectives.

Risks Associated With Exploration And Development
--------------------------------------------------

Our operations are subject to delays and cost overruns, and our activities
  may not be profitable

     We intend to  increase  our  exploration  activities  and to  continue  our
development   activities.   Exploratory   drilling  and,  to  a  lesser  extent,
developmental drilling of oil and gas reserves involve a high degree of risk. We
have  recently  expanded  and plan to increase our capital  expenditures  on our
exploration efforts,  which involve a higher degree of risk than our development
activities.  It is possible that we will not obtain any commercial production or
that drilling and completion costs will exceed the value of production. The cost
of  drilling,  completing  and  operating  wells  is often  uncertain.  Numerous
factors,   including  title  problems,   weather  conditions,   compliance  with
governmental  requirements and shortages or delays in the delivery of equipment,
may curtail, delay or cancel drilling operations.  Furthermore,  completion of a
well does not  assure a profit on the  investment  or a  recovery  of  drilling,
completion and operating costs.

We conduct waterflood projects and other secondary recovery operations

     Secondary recovery operations involve certain risks,  especially the use of
waterflooding  techniques,  and drilling activities in general. Our inventory of
development  prospects  includes  waterflood  projects.   With  respect  to  our
properties  located  in  the  Permian  Basin,  we  have  identified  significant
potential  expenditures  related to  further  developing  existing  waterfloods.
Waterflooding  involves  significant capital  expenditures and uncertainty as to
the total amount of recoverable  secondary reserves.  In waterflood  operations,
there is generally a delay  between the  initiation  of water  injection  into a
formation containing hydrocarbons and any increase in production.  The operating
cost per unit of production of  waterflood  projects is generally  higher during
the initial  phases of such projects due to the purchase of injection  water and
related costs.  Costs are also higher during the later stages of the life of the
project as crude oil production declines.  The degree of success, if any, of any
secondary recovery program depends on a large number of

                                       16
<PAGE>

     factors,  including  the amount of primary  production,  the  porosity  and
permeability  of the  formation,  the technique  used,  the location of injector
wells and the spacing of both producing and injector wells.

We Are Subject to Casualty Risks in Our Onshore And Offshore Activities
-------------------------------------------------------------------------

     Our oil and gas business  involves a variety of operating risks,  including
unexpected  formations or pressures,  uncontrollable flows of oil, gas, brine or
well  fluids  into  the  environment  (including   groundwater   contamination),
blowouts, fires, explosions,  pollution,  marine hazards and other risks, any of
which could cause  personal  injuries,  loss of life,  damage to properties  and
substantial  losses.  Although we carry  insurance at levels that we believe are
reasonable, we are not fully insured against all risks. We do not carry business
interruption  insurance except on rare occasion.  Losses and liabilities arising
from uninsured or  under-insured  events could  materially  affect our financial
condition and operations.

We Hedge Our Oil And Gas Production
-----------------------------------

     As of December 31,  2000,  we had hedged  approximately  (i) 15% of our gas
production through December 31, 2001, and (ii) 65% of our oil production through
June 30, 2001.  These hedges have in the past involved fixed price  arrangements
and other price arrangements at a variety of prices, floors and caps. We have in
the past and may in the future enter into oil and gas futures contracts, options
and swaps. Our hedging  activities,  while intended to reduce our sensitivity to
changes  in  market  prices  of oil and gas,  are  subject  to a number of risks
including  instances in which we or the  counterparties to our hedging contracts
could fail to perform. Additionally, the fixed price sales and hedging contracts
limit the  benefits we will  realize if actual  prices  rise above the  contract
prices.

Our Operations Are Subject to Many Laws And Regulations
--------------------------------------------------------

     The oil and gas industry is heavily regulated.  Extensive  federal,  state,
local and  foreign  laws and  regulations  relating to the  exploration  for and
development,  production,  gathering  and  marketing  of oil and gas  affect our
operations.  Some of the regulations  set forth standards for discharge  permits
for drilling  operations,  drilling  and  abandonment  bonds or other  financial
responsibility  requirements,  reports  concerning  operations,  the  spacing of
wells,  unitization  and pooling of properties and taxation.  From time to time,
regulatory agencies have imposed price controls and limitations on production by
restricting  the  rate of flow of oil and  gas  wells  below  actual  production
capacity to conserve supplies of oil and gas.

     Numerous  environmental laws, including but not limited to, those governing
management  of waste,  protection  of  water,  air  quality,  the  discharge  of
materials into the environment, and preservation of natural resources impact and
influence our operations. If we fail to comply with environmental laws regarding
the discharge of oil, gas, or other materials into the air, soil or water we may
be subject to liabilities to the government and third parties,  including  civil
and  criminal  penalties.  These  regulations  may  require us to incur costs to
remedy the  discharge.  Laws and  regulations  protecting the  environment  have
become more stringent in recent years, and may, in certain circumstances, impose
retroactive,  strict, and joint and several liability,  potentially resulting in
liability for environmental  damage regardless of negligence or fault. From time
to time,  we have agreed to indemnify  sellers of producing  properties  against
certain liabilities for environmental claims associated with such properties. We
cannot  assure  that  new  laws  or  regulations,  or  modifications  of or  new
interpretations   of  existing   laws  and   regulations,   will  not   increase
substantially  the  cost  of  compliance  or  adversely  affect  our oil and gas
operations and financial  condition.  Material  indemnity  claims may also arise
with respect to  properties  acquired by or from us. While we do not  anticipate
incurring  material  costs  in  connection  with  environmental  compliance  and
remediation, we cannot guarantee that we will not incur material costs.

We Are Subject to Substantial Competition
------------------------------------------

     We encounter substantial competition in acquiring properties,  drilling for
new reserves,  marketing oil and gas,  securing trained  personnel and operating
our properties. Many competitors have financial and other resources that

                                       17
<PAGE>

     substantially  exceed  our  resources.  Our  competitors  in  acquisitions,
development, exploration and production include major oil companies, natural gas
utilities,  numerous  independents,   individual  proprietors  and  others.  Our
competitors  may be able to pay more  for  desirable  leases  and may be able to
evaluate,  bid for and purchase a greater number of properties or prospects than
our financial or personnel resources will permit.

Our Business May Be Adversely Affected If We Lose Our Key Personnel
--------------------------------------------------------------------

     We depend greatly upon three key individuals within our management: Gary C.
Evans,  Matthew C. Lutz and Richard R. Frazier.  The loss of the services of any
one of these individuals could materially impact our operations.

Shares Eligible For Future Sale; Absence of Dividends
------------------------------------------------------

     The market price of our common  stock could be adversely  affected by sales
of  substantial  amounts of common stock in the public market or the  perception
that such sales could occur

     We are authorized to issue up to 100,000,000  shares of common stock. As of
March 20, 2001,  35,399,739  shares were issued and  outstanding,  and 4,938,449
shares were  reserved  for  issuance  upon the  exercise of certain  outstanding
warrants and options. Issuing additional shares of common stock pursuant to such
outstanding  options and warrants would reduce the  proportionate  ownership and
voting rights of the common stock then outstanding.  Our existing management and
their  affiliates own 2,974,780 shares of common stock that may in the future be
sold in compliance  with Rule 144 adopted under the  Securities  Act of 1933. In
addition,  our primary credit facility contains a debt to  capitalization  ratio
covenant  requiring us to maintain a ratio of .80 to 1.0. The  possibility  that
substantial  amounts  of  common  stock  may be sold in the  public  market  may
adversely  affect  prevailing  and future market prices for the common stock and
could impair our ability to raise capital through the sale of equity  securities
in the future.

We have never paid cash dividends on our common stock

     We have not  previously  paid any cash dividends on the common stock and do
not anticipate  paying dividends on the common stock in the foreseeable  future.
We intend to reinvest all available  funds for the  development of our business.
In addition, we cannot pay any dividends on the common stock unless and until we
pay all dividend  rights on outstanding  preferred  stock which have in the past
been paid on a timely  basis.  Our primary  credit  facility  and the  indenture
governing  our 10%  Senior  Notes due 2007 also  restrict  the  payment  of cash
dividends on certain securities.

Preferred Stock; Anti-takeover Provisions
------------------------------------------

We have outstanding preferred stock and have the ability to issue more

     Our common stock is  subordinate  to all  outstanding  classes of preferred
stock in the payment of dividends and other  distributions  made with respect to
the stock,  including  distributions  upon  liquidation or dissolution of Magnum
Hunter. Our Board of Directors is authorized to issue up to 10,000,000 shares of
preferred stock without first obtaining shareholder approval,  except in limited
circumstances.  We have  previously  issued several  series of preferred  stock,
although only the 1996 Series A Convertible  Preferred Stock and the 1999 Series
A 8% Convertible Preferred Stock, are currently outstanding.  The holders of the
1996 Series A Convertible  Preferred  Stock  currently have the right to appoint
one additional member to the Board of Directors and upon certain  circumstances,
up to 75%  of our  Board.  The  holders  of the  1999  Series  A 8%  Convertible
Preferred  Stock  currently have the right to nominate two members of our Board,
and,  subject to the rights of the 1996  Series A  Convertible  Preferred  Stock
holders,  upon  certain  circumstances  have the  right to  nominate  additional
directors.  If we designate or issue other  series of preferred  stock,  it will
create additional securities that will have dividend and liquidation preferences
over the common stock.  If we issue  convertible  preferred  stock, a subsequent
conversion may dilute the current shareholders' interest.

                                       18
<PAGE>

Certain anti-takeover provisions may affect your rights as a stockholder

     Our Articles of  Incorporation  and Bylaws include certain  provisions that
may encourage persons considering  unsolicited tender offers or other unilateral
takeover  proposals to negotiate with our Board of Directors  rather than pursue
non-negotiated  takeover  attempts.  These provisions  include authorized "blank
check"  preferred  stock and the  availability of authorized but unissued common
stock.  In addition,  on January 9, 1998, we adopted a shareholder  rights plan.
Under the shareholder  rights plan, the rights initially  represent the right to
purchase  one  one-hundredth  of a share of 1998  Series A Junior  Participating
Preferred Stock for $35.00 per one  one-hundredth  of a share. The rights become
exercisable only if a person or a group acquires or commences a tender offer for
15% or more of our common  stock.  Until they become  exercisable,  these rights
attach  to and  trade  with our  common  stock.  The  rights  issued  under  the
shareholder  rights plan expire January 20, 2008.  Issuing  preferred  stock may
delay  or  prevent  a  change  in  control  of  Magnum  Hunter  without  further
shareholder  action and may  adversely  affect the rights and powers,  including
voting rights,  of the holders of common stock.  In certain  circumstances,  the
issuance of preferred  stock could depress the market price of the common stock.
In  addition,  a change  of  control,  as  defined  under the 10%  Senior  Notes
indenture,  would  entitle the  holders of our 10% Senior  Notes due 2007 to put
those notes to Magnum  Hunter under the indenture  governing  such notes and the
lenders to  accelerate  payment  of  outstanding  indebtedness  under our credit
facility. Both of these events could discourage takeover attempts by making such
attempts more expensive.


Item 2.           Description of Properties

Oil and Gas Reserves
--------------------

General

     All  information  set forth in this Form 10-K  regarding  estimated  Proved
Reserves, related estimated future net cash flows and PV-10 of the Company's oil
and gas  interests  is taken from  reports  prepared by Ryder  Scott  Company of
Houston,  Texas,  Cawley Gillespie & Associates,  Inc. of Fort Worth,  Texas and
DeGoyler and MacNaughton of Dallas,  Texas, all independent  petroleum engineers
with respect to the Company's  interests at December 31, 2000 (using oil and gas
prices in effect at December 31,  2000) and by Ryder Scott  Company and Pollard,
Gore and Harrison of Austin, Texas for December 31, 1999. The estimates of these
independent  petroleum  engineers  were based upon  their  review of  production
histories  and  other  geological,  economic,  ownership  and  engineering  data
provided by the Company.

     PV-10 is the present value of Proved  Reserves  which is an estimate of the
discounted  future  net cash  flows  from each of the  Company's  properties  at
December 31, 2000,  or as otherwise  indicated.  Net cash flow is defined as net
revenues less, after deducting  production and ad valorem taxes,  future capital
costs and operating  expenses,  but before  deducting  federal income taxes. The
future net cash flows have been discounted at an annual rate of 10% to determine
their "present value." The present value is shown to indicate the effect of time
on the value of the revenue stream and should not be construed as being the fair
market value of the properties.  Estimates have been made using constant oil and
gas prices and operating costs, at December 31, 2000, or as otherwise indicated.

                                       19
<PAGE>

     The estimates of future net cash flows from Proved Reserves and their PV-10
are made  using  oil and gas  sales  prices  in  effect  as of the dates of such
estimates  and are held  constant  throughout  the life of the  properties.  The
Company's  estimates  of Proved  Reserves,  future net cash flows and PV-10 were
estimated  using the following  weighted  average  prices,  before  deduction of
production taxes:


                                 Prices used in Reserve Reports at December 31,
                                ------------------------------------------------
                                     2000              1999              1998
                                ------------------------------------------------

Gas (per Mcf)..................      $ 9.28             $2.25            $2.12
Oil (per Bbl)..................      $25.59            $24.03            $9.42

     All reserves are evaluated at contract  temperature  and pressure which can
affect the measurement of gas reserves.  Operating costs,  development costs and
certain production related and ad valorem taxes were deducted in arriving at the
estimated  future net cash flows.  No provision was made for income  taxes.  The
estimates   following  this  section  set  forth   reserves   considered  to  be
economically  recoverable under normal operating methods and existing conditions
at the prices and operating costs  prevailing at the dates indicated  above. The
estimates of the PV-10 from future net cash flows  differ from the  standardized
measure  of  discounted  future  net cash  flows  set  forth in the notes to the
Consolidated  Financial  Statements of the Company,  which is  calculated  after
provision  for  future  income  taxes.  There  can be no  assurance  that  these
estimates  are  accurate  predictions  of future net cash flows from oil and gas
reserves or their present value.

     Proved Reserves are estimates of oil and gas to be recovered in the future.
Reservoir  engineering  is a  subjective  process  of  estimating  the  sizes of
underground  accumulations  of oil and gas that  cannot be  measured in an exact
way.  The  accuracy  of any  reserve  estimates  is a function of the quality of
available data and of engineering  and geological  interpretation  and judgment.
Reserve  reports of other  engineers  might  differ from the  reports  contained
herein.  Results of drilling,  testing, and production subsequent to the date of
the estimate may justify  revision of such estimate.  Future prices received for
the sale of oil and gas will likely be  different  from those used in  preparing
these reports.  The amounts and timing of future operating and development costs
may also  differ  from those  used.  Accordingly,  reserve  estimates  are often
different from the quantities of oil and gas that are ultimately recovered.

     Except for the effect of changes in oil and gas prices,  no major discovery
or other  favorable  or adverse  event is believed to have caused a  significant
change in these  estimates of the Company's  Proved  Reserves since December 31,
2000.  No  estimates  of Proved  Reserves  of oil and gas have been filed by the
Company  with,  or included  in any report to, any United  States  authority  or
agency  (other than the  Securities  and Exchange  Commission)  since January 1,
2000.

                                       20
<PAGE>

Company Reserves

     The following tables set forth the estimated Proved Reserves of oil and gas
of the Company and the PV-10  thereof on an actual  basis at December  31, 2000,
1999 and 1998.

                Estimated Proved Oil and Natural Gas Reserves (a)

                                                       At December 31,
                                  ----------------------------------------------
                                    2000                1999               1998
                                  ----------------------------------------------

Net gas reserves (Mcf):
     Proved developed............  179,697,015      184,954,732      174,987,374
     Proved undeveloped..........   53,511,550       45,044,794       44,072,300
                                  ----------------------------------------------
       Total proved gas reserves.  233,208,565      229,999,526      219,059,674
                                  ==============================================
Net oil reserves (Bbl):
    (including condensate and NGL)
     Proved developed............   13,923,380       16,299,585        9,474,591
     Proved undeveloped..........    8,380,082        9,234,165        7,874,050
                                  ----------------------------------------------
       Total proved oil reserves.   22,303,462       25,533,750       17,348,641
                                  ==============================================
Total Proved Reserves (Mcfe).....  367,029,337      383,202,026      323,151,521
                                  ==============================================

                     Estimated PV-10 of Proved Reserves (a)

                                                   At December 31,
                                   ---------------------------------------------
                                    2000               1999              1998
                                   ---------------------------------------------
Estimated PV-10 (b) :
     Proved developed............  $  829,683,640  $  282,481,193  $ 160,984,895
     Proved undeveloped .........     269,843,116      87,609,991     18,424,052
                                   ---------------------------------------------
       Proved Reserves PV-10 (c).  $1,099,526,756  $  370,091,184  $ 179,408,947
                                   =============================================

------------

     (a) Based upon  reserve  reports at  December  31,  2000  prepared by Ryder
Scott,  Cawley  Gillespie and D&M and at December 31, 1999 and December 31, 1998
prepared by Ryder Scott and PG&H.

     (b) PV-10 differs from the  standardized  measure of discounted  future net
cash flows set forth in the notes to the  Consolidated  Financial  Statements of
the Company, which is calculated after provision for future income taxes.

     (c) The standardized measure of discounted future net cash flows related to
proved oil and gas reserves at December 31, 2000,  1999 and 1998,  respectively,
were as follows: $804,923,000, $315,616,000 and $176,148,000.

       Significant Properties

     On December 31, 2000, 100% of the Company's Proved Reserves on a Bcfe basis
were located in the Mid-  Continent  Area, the Permian Basin Region and the Gulf
Coast/Gulf of Mexico.  On such date, the Company's  properties  included working
interests in 3,043 gross (1,720 net) productive oil and gas wells.

                                       21
<PAGE>

     The  following  table sets forth  summary  information  with respect to the
Company's estimated Proved Reserves of oil and gas at December 31, 2000.
<TABLE>
<CAPTION>
<S>                                    <C>               <C>           <C>           <C>            <C>
                                               PV-10 (a)                           Proved Reserves
                                     ----------------------------------------------------------------------------
                                                                                                    Natural Gas
                                           Amount         % of          Oil             Gas          Equivalent
                                       (in thousands)     Total        (Bbl)           (Mcf)           (Bcfe)
                                     -------------------------------------------- --------------- ---------------
Mid-Continent Area (b)...............           505,186    45%           7,959,245    118,558,470      166.31
Permian Basin Region (b).............           391,532    36%          12,474,315     83,869,110      158.72
Gulf Coast/Gulf of Mexico (c) .......           202,809    19%           1,869,902     30,780,985       42.00
                                     ----------------------------------------------------------------------------
       Total.........................         1,099,527   100%          22,303,462    233,208,565      367.03
                                     ============================================================================
</TABLE>
----------

     (a) PV-10 differs from the  standardized  measure of discounted  future net
cash flows set forth in the notes to the  Consolidated  Financial  Statements of
the Company, which is calculated after provision for future income taxes.

     (b) Based on reserve  reports at December 31, 2000  prepared by Ryder Scott
and Cawley Gillespie.

     (c) Based on reserve  reports at December 31, 2000  prepared by Ryder Scott
and D&M.

Oil and Gas Production, Prices and Costs

     The following table shows the  approximate  net production  attributable to
the  Company's  oil and gas  interests,  the average sales price and the average
production expense  attributable to the Company's oil and gas production for the
periods  indicated.  Production  and sales  information  relating to  properties
acquired  or  disposed  of is  reflected  in this  table only since or up to the
closing  date of  their  respective  acquisition  or sale  and  may  affect  the
comparability of the data between the periods presented.
<TABLE>
<CAPTION>
<S>                                                     <C>            <C>                <C>
                                                                  Year Ended December 31,
                                                          2000             1999              1998
                                                   ---------------------------------------------------------
Oil and gas production:
  Oil (Mbbl)......................................              1,298           1,307             1,141
  Gas (MMcf)......................................             19,579          19,026            14,119
  Natural Gas Equivalents (MMcfe).................             27,368          26,868            20,965
Average sales price (a):
  Before Hedge Contracts:
     Oil (per Bbl)................................        $     28.91     $     17.55       $     11.79
     Gas (per Mcf)................................               4.08            2.16              1.90
     Natural Gas Equivalents (per Mcfe)...........               4.28            2.38              1.92
  After Hedge Contracts:
     Oil (per Bbl)................................        $     22.95     $     15.01       $     12.67
     Gas (per Mcf)................................               3.90            2.16              2.02
     Natural Gas Equivalents (per Mcfe)...........               3.88            2.26              2.05
Oil and gas production lifting costs (per Mcfe) ..                .60             .57               .68
Production taxes and other costs (per Mcfe) (b)...        $       .46     $       .30       $       .31
</TABLE>
----------

     (a) Before deduction of production taxes and net of hedging results.

     (b) Includes ad valorem taxes,  insurance,  bonds, company overhead and net
profits interest.

                                       22
<PAGE>

Drilling Activity

     The  following  table sets  forth the  results  of the  Company's  drilling
activities during the three fiscal years ended December 31, 2000, 1999 and 1998.
<TABLE>
<CAPTION>
<S>           <C>                 <C>         <C>                 <C>             <C>          <C>               <C>
                                               Gross Wells (a)                                 Net Wells (b)
    Year         Type of Well       Total      Producing (c)       Dry (d)          Total      Producing (c)      Dry (d)
    ----         ------------       -----      -------------       -------          -----      -------------      -------
    2000       Exploratory
                 Texas                13              12               1             2.82             2.51         0.31
                 Oklahoma              1               1               0             0.25             0.25            0
                 New Mexico            6               6               0             2.23             2.23            0
                 Other                16              15               1             6.12             5.63         0.50
               Development
                 Texas                47              47               0            23.10            23.10            0
                 Oklahoma              1               1               0             0.50             0.50            0
                 New Mexico            2               2               0             1.18             1.18            0
                 Other                 2               2               0             0.33             0.33            0

    1999       Exploratory
                 Texas                 6               5               1             2.77             2.46         0.31
                 Oklahoma              1               1               0             0.18             0.18            0
                 New Mexico            0               0               0                0                0            0
                 Other                 7               5               2             2.38             1.88         0.50
               Development
                 Texas                10              10               0             9.14             9.14            0
                 Oklahoma              3               1               2             3.00             1.00            2
                 New Mexico            3               3               0             2.34             2.34            0
                 Other                 1               1               0             0.25             0.25            0

    1998       Exploratory
                 Texas                 5               4               1             3.25             2.64         0.61
                 Oklahoma              0               0               0                0                0            0
                 New Mexico            1               1               0              .05              .05            0
                 Other                 0               0               0                0                0            0
               Development
                 Texas                79              79               0             74.4             74.4            0
                 Oklahoma              0               0               0                0                0            0
                 New Mexico            5               5               0                5                5            0
                 Other                 0               0               0                0                0            0
</TABLE>
----------

     (a) The  number  of gross  wells is the  total  number  of wells in which a
working  interest  is owned.  Fluid  injection  wells for  waterflood  and other
enhanced recovery projects are not included as gross wells.
     (b) The  number of net  wells is the sum of  fractional  working  interests
owned in gross wells expressed as whole numbers and fractions thereof.
     (c) A producing  well is an  exploratory  or  development  well found to be
capable of  producing  either  oil or gas in  sufficient  quantities  to justify
completion as an oil or gas well.
     (d) A dry  well  is an  exploratory  or  development  well  that  is  not a
producing well.

                                       23
<PAGE>

Oil and Gas Wells

     The  following  table sets forth the number of oil and natural gas wells in
which the Company had a working  interest at  December  31,  2000.  All of these
wells are located in the United States.
<TABLE>
<CAPTION>
<S>                         <C>            <C>           <C>              <C>           <C>            <C>
                                                                Productive Wells
                                                            As of December 31, 2000
------------------------------------------------------------------------------------------------------------------------------------
                                            Gross (a)                                    Net (b)
Location                        Oil           Gas           Total           Oil            Gas           Total
--------                        ---           ---           -----           ---            ---           -----
Texas......................    1,374          745           2,119            702            491           1,193
Offshore Texas ............        0            3               3              0              1               1
Oklahoma...................      140          275             415             84            164             248
Mississippi................        1            0               1              0              0               0
New Mexico.................      148          282             430             73            167             240
California.................        5            0               5              1              0               1
Offshore Louisiana.........        0           24              24              0              9               9
Arkansas...................       46            0              46             28              0              28
                           ---------------------------------------------------------------------------------------------------------
         Total.............    1,714        1,329           3,043            888            832           1,720
                           =========================================================================================================
</TABLE>
----------

     (a) The  number  of gross  wells is the  total  number  of wells in which a
working interest is owned. Well counts include wells with multiple completions.
     (b) The  number of net  wells is the sum of  fractional  working  interests
owned in gross wells expressed as whole numbers and fractions thereof.

Oil and Gas Acreage

     The following  table  summarizes  the Company's  developed and  undeveloped
leasehold acreage at December 31, 2000.
<TABLE>
<CAPTION>
<S>                                     <C>                   <C>               <C>                  <C>
                                                     Developed                              Undeveloped
                                                     ---------                              -----------
                                          Gross (a)             Net (b)          Gross (a)            Net (b)
                                          ---------             -------          ---------            -------
Offshore...........................          80,320              31,040           113,360              32,110
Texas..............................         260,000             215,000            75,000              40,000
Oklahoma...........................         100,000              72,000             7,000               3,400
Mississippi........................             528                 452                 -                   -
New Mexico.........................          42,000              36,000                 -                   -
California.........................             509                  38                 -                   -
                                   -------------------------------------------------------------------------------------
      Total .......................         483,357             354,530           195,360              75,510
                                   =====================================================================================
</TABLE>
----------

     (a) The  number  of gross  acres is the  total  number  of acres in which a
working interest is owned.
     (b) The  number of net  acres is the sum of  fractional  working  interests
owned in gross acres expressed as whole numbers and fractions thereof.

                                       24
<PAGE>

     Substantially  all  of  the  Company's   interests  are  leasehold  working
interests  or  overriding  royalty  interests  (as  opposed  to  mineral  or fee
interests)  under  standard  onshore oil and gas leases.  As is customary in the
industry,  the  Company  generally  acquires  oil and gas  acreage  without  any
warranty of title except as to claims made by, through or under the  transferor.
Although the Company has title  examined by a landman or title attorney prior to
acquisition of mineral acreage in those cases in which the economic significance
of the acreage  justifies the cost,  there can be no assurance  that losses will
not result from title  defects or from  defects in the  assignment  of leasehold
rights.  In certain  instances,  title  opinions  may not be obtained if, in the
Company's judgment, it would be uneconomical or impractical to do so.

Item 3.           Legal Proceedings.

     No legal  proceedings  are pending other than ordinary  routine  litigation
incidental to the Company's  business,  the outcome of which management believes
will not have a material adverse effect on the Company.

Item 4.           Submission of Matters to a Vote of Security Holders.

     The Company had no matters  requiring a vote of security holders during the
fourth quarter of 2000.

                                     PART II

Item 5.           Market for Common Equity and Related Stockholder Matters.

     The Common  Stock of the  Company  has been  listed on the  American  Stock
Exchange  since March 8, 1996. The Common Stock has been listed under the ticker
symbol "MHR" since March 18,  1997,  prior to which time it was listed under the
ticker symbol "MPM." At March 20, 2001, there were 3,319 stockholders of record.
<TABLE>
<CAPTION>
<S>                                                                  <C>           <C>            <C>
                                                                                                  Average Daily
                                                                                                  Trading Volume
                                                                       High           Low            (Shares)
                                                                  -------------------------------------------------
2000
   First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . .$ 4.06        $ 2.56            34,688
   Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6.63        $ 3.38            45,703
   Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . .$ 9.13        $ 5.88            80,593
   Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . $10.81        $ 6.50           106,183
1999
   First Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . .$ 3.19        $ 2.50            53,351
   Second Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4.19        $ 2.75            45,792
   Third Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . .$ 4.25        $ 3.19            25,211
   Fourth Quarter . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3.94        $ 2.50            46,576
</TABLE>

     On March 20, 2001,  the last reported  sale price of the  Company's  Common
Stock on the American Stock Exchange was $11.88 per share.

     The Company has not previously  paid any cash dividends on its Common Stock
and does not anticipate  paying dividends on its Common Stock in the foreseeable
future. It is the present intention of management to utilize all available funds
for the development of the Company's  business  activities.  The Company may not
pay any  dividends  on Common  Stock  unless  and until all  dividend  rights on
outstanding  Preferred Stock have been satisfied.  The Company's existing credit
facility restricts the payment of cash dividends on the Company's securities.

                                       25
<PAGE>

Item 6.           Selected Financial Data

     The  selected  historical  financial  data sets  forth  summary  historical
consolidated  financial  data  of the  Company  as of and for  the  years  ended
December 31, 2000,  1999, 1998, 1997, and 1996, which have been derived from the
Company's  audited  consolidated  financial  statements and notes  thereto.  The
selected  historical  financial data is qualified in its entirety by, and should
be read in conjunction with  "Management's  Discussion and Analysis of Financial
Condition and Results of Operations" and the financial  statements and the notes
thereto  included  elsewhere  in this  Form  10-K.  For  additional  information
relating to the Company's  operations,  see "Business" and "Properties." Certain
reclassifications  have been made to the selected  historical  financial data of
the prior years, as well as to certain quarterly financial data, to conform with
the current presentation. All data is in thousands, except per share data.

<TABLE>
<CAPTION>
<S>                                                <C>            <C>            <C>          <C>             <C>
                                                      1996           1997           1998          1999             2000
                                                   ----------     ----------     ----------   ------------    -------------
Income Statement Data:
Total operating revenues..........................    $16,412        $ 48,834       $ 51,400       $ 69,626       $127,510

Total operating costs and expenses (a)............     13,541          38,833         94,414         54,514         77,181
                                                  -------------------------------------------------------------------------
Operating profit (loss)...........................      2,871          10,001        (43,014)        15,112         50,329
Income (loss) before extraordinary loss...........        509          (2,128)       (47,080)        (6,826)        22,260
Extraordinary loss from early extinguishment
  of debt, net of taxes ..........................          -          (1,384)             -              -              -
Net Income (loss) ................................        509          (3,512)       (47,080)        (6,826)        22,260
Dividends applicable to preferred shares (b)......       (406)           (875)          (875)        (4,509)        (9,708)
Income (loss) applicable to common shares.........    $   103        $ (4,387)      $(47,955)      $(11,335)      $ 12,552
Income (loss) per common share before
 extraordinary item
   Basic (b)......................................    $  0.01        $  (0.21)      $  (2.27)      $  (0.57)      $   0.60
   Diluted (b)....................................    $  0.01        $  (0.21)      $  (2.27)      $  (0.57)      $   0.51
Income (loss) per common share after
 extraordinary item
   Basic (b)......................................    $  0.01        $  (0.30)      $  (2.27)      $  (0.57)      $   0.60
   Diluted (b)....................................    $  0.01        $  (0.30)      $  (2.27)      $  (0.57)      $   0.51

Other Data:
EBITDA (c)........................................    $ 6,166        $ 22,740       $ 22,112       $ 37,538       $ 76,362
Capital expenditures (d)..........................    $41,471        $160,059       $ 70,187       $ 59,968       $ 64,311
</TABLE>
--------

     (a) Includes in 1998 the non-cash  write-down of $42.745 million of oil and
gas properties in the full-cost pool due to the ceiling test limitation.

     (b) Includes the effect in the year 2000 of the payment of $5.5 million fee
paid upon redemption of $25.0 million  (liquidation value) of the Company's 1999
Series A 8%  Convertible  preferred  stock.  The fee was  treated as a dividend,
reducing  income per common  share,  basic and  diluted,  by $0.26 per share and
$0.17 per share, respectively, for the year 2000.

     (c) EBITDA is defined as income  (loss)  before  income  taxes and minority
interest,  plus the sum of depletion  and  depreciation  and  interest  expense.
EBITDA  is not a  measure  of cash  flow as  determined  by  generally  accepted
accounting  principles.  The Company has included information  concerning EBITDA
because  EBITDA  is a measure  used by  certain  investors  in  determining  the
Company's  historical ability to service its indebtedness.  EBITDA should not be
considered as an  alternative  to, or more  meaningful  than, net income or cash
flows as determined in accordance with generally accepted accounting  principles
or as an indicator of the Company's operating performance or liquidity.

     (d) Capital expenditures include cash expended for acquisitions plus normal
additions  to  oil  and  natural  gas   properties   and  other  fixed   assets.
Additionally,  the year  2000  amount  includes  the cost of  property  acquired
through the issuance of common stock with a fair market value of $3.481  million
on the acquisition date.

                                       26
<PAGE>

<TABLE>
<CAPTION>
<S>                                                <C>           <C>           <C>            <C>              <C>
                                                      1996          1997          1998           1999             2000
                                                    ---------     ---------    -----------    -----------     ------------
Balance Sheet Data:
Working capital (deficiency).......................  $  2,279      $  2,610     $   (1,203)     $  (1,314)       $   4,121
Property, plant and equipment, net.................    73,648       221,259        228,436        265,195          260,532
Total assets.......................................    83,072       251,069        265,724        304,022          315,612
Total debt (a).....................................    38,766       161,543        231,020        234,806          191,139
Stockholders' equity...............................  $ 35,154      $ 72,152     $   19,697      $  51,552        $  93,416
</TABLE>
-----------

     (a) Consists of long-term debt,  including current  maturities of long-term
debt,  and excluding  production  payment  liabilities  of $937  thousand,  $743
thousand,  $633  thousand,  $460  thousand and $359  thousand as of December 31,
1996, 1997, 1998, 1999 and 2000, respectively. As of December 31, 2000, 1999 and
1998, $20.6 million, $41.8 million and $26.0 million,  respectively, of the debt
was non-recourse to the Company.

     The following table sets forth  unaudited  summary  financial  results on a
quarterly basis for the two most recent years.
<TABLE>
<CAPTION>
<S>                                                <C>             <C>           <C>                 <C>
                                                                                 2000
                                                    ---------------------------------------------------------------
                                                       First          Second          Third             Fourth
                                                   --------------  -------------  --------------   ----------------
Revenues...........................................    $   25,393     $   28,286      $   30,689         $   43,142
Depreciation, depletion and amortization...........         5,971          5,566           5,398              8,621
Net Operating Profit...............................         8,139         10,847          13,244             18,099
Net Income.........................................         1,580          3,528           4,874             12,278
Income per common share, basic (a).................    $     0.02     $     0.13      $     0.20         $     0.24
Income per common share, diluted (a)...............    $     0.02     $     0.12      $     0.15         $     0.19
</TABLE>

<TABLE>
<CAPTION>
<S>                                                  <C>             <C>             <C>               <C>
                                                                                 1999
                                                    ---------------------------------------------------------------
                                                       First           Second          Third            Fourth
                                                   --------------  --------------  -------------   ----------------
Revenues...........................................   $    13,105     $    15,359    $    19,864       $     21,298
Depreciation, depletion and amortization...........         5,148           5,467          5,768              5,689
Net Operating Profit...............................         1,266           2,539          5,539              5,768
Net Income (Loss)..................................        (4,962)         (2,340)           213                263
Loss per common share, basic.......................   $     (0.29)    $     (0.18)   $     (0.05)      $      (0.05)
Loss per common share, diluted.....................   $     (0.29)    $     (0.18)   $     (0.05)      $      (0.05)
</TABLE>

     (a) Includes  the effect in the fourth  quarter of 2000 of the payment of a
$5.5 million fee paid upon redemption of $25 million  (liquidation value) of the
Company's 1999 Series A 8% Convertible preferred stock. The fee was treated as a
dividend, reducing income per common share, basic and diluted by $0.22 per share
and $0.15 per share, respectively, for the fourth quarter of 2000.

                                       27
<PAGE>

Item 7.     Management Discussion and Analysis of Financial Condition
              and Results of Operations

Results of Operations

     The following  discussion and analysis  should be read in conjunction  with
the Company's  consolidated  financial  statements and the notes associated with
them contained elsewhere in this report. This discussion should not be construed
to imply that the results  discussed herein will  necessarily  continue into the
future or that any conclusion  reached herein will  necessarily be indicative of
actual operating results in the future. Such discussion represents only the best
present assessment by management of the Company.

     The Company's results of operations have been significantly affected by our
success in  acquiring  oil and gas  properties  and our  ability to  maintain or
increase oil and natural gas production  through  exploration  and  exploitation
activities.  Fluctuations in oil and gas prices have also significantly affected
the results of operations.

     On  December  31,  1998,  the Company  through its newly  formed 100% owned
subsidiary,  Bluebird,  acquired from Spirit Energy 76 ("Spirit 76") natural gas
reserves  and  associated  assets in  producing  fields  located in Oklahoma and
Texas.  As part of the  capitalization  of  Bluebird,  the  Company  contributed
1,840,271 units of TEL Offshore Trust. Bluebird, as an "unrestricted subsidiary"
as defined  under  certain  credit  agreements,  is neither a  guarantor  of the
Company's  10%  Senior  Notes  due 2007 nor can it be  included  in  determining
compliance  with  certain   financial   covenants  under  the  Company's  credit
agreements.

     On June 8, 1999, the Company and Bluebird acquired oil and gas reserves and
related  assets from Vastar  including  interests in 476 wells, a gas processing
plant and two gas gathering systems located in the states of Texas, Oklahoma and
Arkansas.

     On  December  1, 1999  Bluebird  acquired a 50%  ownership  interest in the
Madill gas processing plant and associated  gathering system located in Marshall
and Bryan counties, Oklahoma. The effective date of the acquisition was November
1, 1999.

     Effective  September  1,  2000 the  Company  acquired  a 5.5%  net  profits
interest in the Panoma production and gas gathering  facilities for $3.5 million
of the  Company's  restricted  common stock.  By acquiring  this  interest,  the
Company  lowered its lease  operating  expense and increased oil field  services
income.

     Effective April 1, 2000 the Company exchanged  interests in certain onshore
oil producing properties for interests in certain offshore oil and gas producing
properties and production facilities located in the Gulf of Mexico in a tax free
like-kind  exchange.  The transaction did not have a material effect on reported
production in 2000, but the Company gained  significantly  increased exposure in
an offshore area of interest where it is conducting exploration activities.

     During  2000,  we  realized  proceeds  of  $43.8  million  from the sale of
non-core oil and gas and other properties,  of which approximately $11.6 million
was attributable to Bluebird.

                                       28
<PAGE>

     The following table sets forth certain  information with respect to our oil
and gas operations and our gas gathering, marketing and processing operations.

                                                      Years Ended
                                        2000            1999            1998
                                    --------------------------------------------
Oil and Gas Operations
--------------------------------------------------------------------------------

Reported Production:
   Oil (MBbls)......................         1,298        1,307           1,141
   Gas (MMcf).......................        19,579       19,026          14,119
   Oil and Gas (MMcfe)..............        27,368       26,868          20,965
   Equivalent Daily Rate (MMcfe/day)          74.8         73.6            57.4
Underlying Production (*):
   Oil (MBbls)......................         1,175        1,041             871
   Gas (MMcf).......................        18,008       16,187          12,399
   Oil and Gas (MMcfe)..............        25,059       22,436          17,625
   Equivalent Daily Rate (MMcfe/day)          68.5         61.5            48.3
       (*) Adjusted for the sale of properties in June and September 2000.

Average Sale Prices (after hedging)
   Oil (per Bbl)....................     $   22.95    $   15.01       $   12.67
   Gas (per Mcf)....................          3.90         2.16            2.02
   Oil and Gas (per Mcfe)...........          3.88         2.26            2.05
Effect of hedging activities (per Mcfe)      (0.41)       (0.12)           0.13
Lease Operating Expense (per Mcfe)
   Lifting costs....................          0.60         0.57            0.68
   Production tax and other costs...          0.46         0.30            0.31
Gross margin (per Mcfe).............    $     2.82    $    1.39       $    1.06

Gas Gathering, Marketing and
   Processing Operations
--------------------------------------------------------------------------------

Throughput Volumes (Mcf per day)
   Gathering........................        16,639       18,536          20,775
   Processing.......................        16,506       21,510          15,668
Gross margin (in thousands).........
   Gathering (per Mcf throughput)...          0.18         0.14            0.11
   Processing (per Mcf throughput)..          0.50         0.16            0.07

Period to Period Comparisons

For the Years Ended December 31, 2000 and 1999

     We reported  record net income of $22.3 million for the year ended December
31,  2000 versus a net loss of $6.8  million for the same period in 1999.  Total
operating revenues increased 83% to a record $127.5 million and operating profit
increased  233% to a record  $50.3  million in 2000. A 72% increase in the price
received  for oil and gas sold (on a thousand  cubic feet  equivalent,  or Mcfe,
basis),  combined  with a 2%  increase in oil and gas  production  (on a million
cubic  feet  equivalent,  or MMcfe,  basis) in our oil and gas  exploration  and
production segment was primarily  responsible for these record results.  We also
reported significant  increases in revenues and gross operating margins from our
gas gathering,  marketing and processing and oil field services segments in 2000
compared to 1999 due to improved product prices and processing  economics and an
increase in customers  for whom we are  providing  operations  services.  Income
applicable to common  shares was $12.6 million in 2000 versus a loss  applicable
to common shares of $11.3  million in 1999.  Income per common share - basic was
$0.60 per share and income per common share -diluted was $0.51 per share in 2000
compared to a loss  applicable to common  shares of $0.57 per share,  both basic
and  diluted,  in 1999.  Income per share in 2000  includes the effect of a $5.5
million  non-recurring  fee paid upon  redemption of $25.0 million  (liquidation
value) of our 1999 Series A 8% Convertible  preferred stock. The fee was treated
as a dividend,  which  reduced  income per common share,  basic and diluted,  by
$0.26 per share and $0.17 per share, respectively, for the year 2000.

                                       29
<PAGE>

Oil and Gas Operations:

     For the year 2000,  we reported  oil  production  of 1,298 Mbbls  (thousand
barrels)  and  gas  production  of  19,579  MMcf  (million  cubic  feet),  which
represents  a decline of 1% in oil and an  increase of 3% in gas  produced  from
1999. Our reported  equivalent  daily rate of production on a million cubic feet
per day basis  (MMcfe/day)  increased 2% to 74.8 MMcfe/day in 2000. The reported
production  in 2000 was  impacted  by the sale of certain  non-core  oil and gas
properties  which  took  effect  in  June  and  September  2000.  Excluding  the
production of these properties from both periods,  our underlying oil production
increased 13% and our underlying  gas production  increased 11% in 2000 compared
to 1999,with the underlying  equivalent daily rate of production  increasing 11%
to 68.5 MMcfe/day . These increases were the result of a full year of production
from the  properties  acquired from Vastar being included in 2000 as well as the
success of our drilling program offsetting normal production declines.

     The  increase  in oil  and  gas  prices  was the  most  significant  factor
affecting the increase in net income in 2000.  Prices  realized in 2000 averaged
$22.95  per  barrel  of oil and  $3.90  per Mcf of gas.  This  represents  a 72%
increase  on a thousand  cubic  feet of gas  equivalent  (Mcfe)  basis over 1999
average  realized  prices of $15.01  per barrel of oil and $2.16 per Mcf of gas.
The unit prices realized include the effects of hedging.

     From time to time,  we enter into  various  hedging  contracts  in order to
reduce our exposure to the  possibility of declining oil and gas prices.  During
2000,  hedging reduced the average price we received for oil by $5.96 per barrel
and for gas by $0.18  per Mcf.  During  2000,  we had  approximately  19% of our
natural gas production and 73% of our oil production  hedged.  Beginning January
1, 2000 we have  approximately 14% of our expected natural gas production hedged
for 2001 at a weighted  average price using cost-less  collars of $4.50 to $6.15
per Mcf and we have  approximately  45% of our expected crude oil production for
the first six months of 2001 hedged at a weighted average price using cost- less
collars of $25.00 to $34.73 per barrel.

     Primarily  as a result  of higher  realized  prices,  oil and gas  revenues
increased 75% to $106.1 million in 2000 compared to $60.7 million in 1999.

     Lease  operating  expenses  consist of two  components,  lifting  costs and
production tax and other costs. For 2000, lifting costs, on a unit of production
basis, were $0.60 per Mcfe as compared to $0.57 per Mcfe in 1999, an increase of
5%.  This  increase in lifting  costs per unit was due to a general  increase in
costs of labor, materials and field services stimulated by higher prices for oil
and  natural  gas.  Production  tax and other  costs were $0.46 per Mcfe in 2000
compared to $0.30 per Mcfe in 1999, an increase of 53%. This was principally due
to an increase of $0.10 per Mcfe in  production  taxes,  which are a function of
higher oil and gas prices,  and an increase in company  overhead  charged to oil
and gas operations of $0.04 per Mcfe due principally to higher labor and benefit
costs.

     Our gross  margin for oil and gas  operations  (oil and gas  revenues  less
lease  operating  expenses)  for 2000 was  $77.1  million,  or $2.82  per  Mcfe,
compared to $37.1  million,  or $1.39 per Mcfe in 1999, an increase of 102% on a
per unit of  production  basis,  primarily  as a result  of  higher  oil and gas
prices.

Gathering, Marketing and Processing Operations:

     For 2000, our gathering system throughput was 16.6 MMcf per day versus 18.5
MMcf per day in 1999, a decline of 10% due to the sale of a gathering  system in
June 1999 and to normal  production  declines behind the system.  Gas processing
throughput  was 16.5 MMcf per day in 2000  versus  21.5 MMcf per day in 1999,  a
decrease of 23%. During  December 1999, we completed  recoupment of our original
investment  in the  McLean  gas  processing  plant.  As a  result,  our share of
operating income and plant  throughput  reverted to 50% from the 100% applicable
during the recoupment period.  The decline in reported  throughput at McLean was
partially  offset  by  our  acquisition  of a 50%  interest  in the  Madill  gas
processing  plant in December  1999.  Also,  our reported  throughput at another
plant was reduced  beginning June 2000 due to the sale of an interest in oil and
gas properties supplying the plant.

                                       30
<PAGE>

     Revenues from gathering,  marketing and processing  increased 144% to $20.0
million in 2000 versus $8.2 million in 1999. Of this increase,  $8.4 million was
due to the  acquisition  of the Madill plant.  Also,  we received  significantly
higher prices for natural gas and plant  products sold in 2000 compared to 1999.
Natural  gas prices  increased  85% while the price  received  for  natural  gas
liquids  increased  62%.  The effect of price  increases  was seen at the McLean
plant,  where our  revenues  declined  only 14%  despite  the 50% decline in our
operating interest due to reversion.

     Operating  costs  for  the  gathering,  marketing  and  processing  segment
increased 166% to $15.7 million in 2000 from $5.9 million in 1999. A substantial
portion of this increase was due to the acquisition of the Madill plant. Our net
share of costs at the McLean plant  declined only 19% despite the reversion to a
50% operating  interest due to higher  natural gas prices  affecting the cost of
plant  throughput.  Higher  natural  gas prices  also  affected  the cost of gas
marketed.

     The gross margin realized from gathering, marketing and processing for 2000
was $4.3  million  versus $2.3  million in 1999,  an increase of 87%.  Gathering
margin  was $0.18 per Mcf in 2000  versus  $0.14 in 1999 due to an  increase  in
marketing spreads. Processing margin was $0.50 per Mcf in 2000 compared to $0.16
per Mcf in 1999 due to higher  prices for plant  products and better  processing
economics.

Oil Field Services Operations:

     Revenues  from oil field  services  were $1.4  million in 2000  versus $768
thousand in 1999 due to an increase in customers for whom we provided operations
services.  Operating costs increased to $903 thousand in 2000 from $350 thousand
in 1999 due to higher  costs for labor and  overhead.  The gross margin for this
segment in 2000 was $545  thousand  versus $418 thousand in 1999, an increase of
30%.

Other Income and Expenses:

     Depreciation  and depletion  expense was $25.6 million in 2000 versus $22.1
million in 1999.  Depreciation and depletion on oil and gas properties was $0.89
per  Mcfe in 2000  versus  $0.79  per Mcfe in 1999.  This  13%  increase  in the
equivalent unit cost was due to an increase in development costs associated with
our  exploration  efforts in the Gulf of Mexico.  Depreciation  expense  for the
gathering,  marketing and processing  segment increased by $230 thousand in 2000
due to the Madill plant acquisition.

     For 2000, we recorded a gain on sale of $28 thousand  versus a gain on sale
of $272 thousand in 1999.  The gain on sale in both periods  relates to the sale
of property other than oil and gas properties. Since we use the full cost method
of  accounting  for oil and gas  properties,  proceeds  from  the  sale of those
properties  are applied to the full cost pool and no gain or loss is recognized.
General and administrative  expense for 2000 increased 110% to $6.1 million from
$2.9 million in 1999.  The  principal  cause of this increase was a $3.1 million
increase in salary,  benefits and retirement plan expenses as a result of higher
headcount,   year-end  incentive  bonuses,   and  ESOP  expense  resulting  from
appreciation  in the Company's  stock price.  The  difference  between the stock
value on the  contribution  date and the  stock  value  when  purchased  must be
expensed at the date the contribution is made to the ESOP. We recorded equity in
earnings of affiliate of $1.3 million in 2000 versus a loss of $103  thousand in
1999.  This  increase  was due to  increased  net  earnings  from gas  marketing
operations of the affiliate. Other income was $477 thousand for 2000 versus $354
thousand in 1999. The increase was caused by an increase in interest income.

     Interest  expense was $22.3 million for 2000 versus $22.1 million for 1999.
During  most of 2000  the  interest  rate on our  LIBOR-based  bank  debt and an
interest  rate swap were higher  than in 1999.  This was offset by a decrease in
outstanding  LIBOR-based  bank debt in the latter  part of 2000 due to  reducing
debt from cash raised from the sale of non- core oil and gas  properties and the
exercise of warrants and options for our common stock.

     We recorded a total  provision  for income tax  expense of $7.6  million in
2000  versus  none in 1999.  The year 2000  provision  included a $234  thousand
current provision due to alternative minimum tax regulations.  The provision for
deferred income tax expense of $7.3 million in 2000 reflects a reduction of $3.9
million in the valuation  allowance  charged  against our deferred tax asset. We
made this reduction in the valuation  allowance in 2000 after  consideration  of
current production levels,  current expectations regarding near-term oil and gas
prices, current hedging positions, anticipated

                                       31
<PAGE>

     capital  expenditures,  the  estimated  reversal of book and tax  temporary
differences, available tax-planning strategies and expectations regarding future
taxable  income.  The valuation  allowance  reduces the deferred tax asset to an
amount  that is  more  likely  than  not to be  realized  based  on the  factors
previously  discussed.  No income tax  benefit was  provided in 1999  because of
uncertainty  at that time in our ability to realize  additional  tax benefits on
our net operating losses in the future.  Dividends applicable to preferred stock
were $9.7  million for 2000 versus $4.5 million in 1999.  The  dividends in 2000
included the $5.5 million premium (non-recurring) on redemption of $25.0 million
(liquidation value) of our 1999 Series A 8% Convertible preferred stock.


For the Years Ended December 31, 1999 and 1998

     We reported a net loss of $6.8 million for the year ended December 31, 1999
versus a net loss of $47.1 million for the same period in 1998.  Total operating
revenues  increased  35% to $69.6  million in 1999 from $51.4 million in 1998. A
10%  increase in the price  realized  for oil and gas on an Mcfe basis  combined
with a 28% increase in oil and gas  production  on an MMcfe basis was  primarily
responsible  for the  increase  in total  operating  revenues.  We  reported  an
operating  profit of $15.1  million in 1999  versus an  operating  loss of $43.0
million in 1998. In 1998 we recognized an impairment of $42.7 million to our oil
and gas properties due to a severe decline in oil and gas prices.  No impairment
provision  was necessary in 1999. We also saw  significant  improvements  in our
daily production rates,  prices and gross margins for our oil and gas operations
as  well  as  improvements  in  our  gas  gathering,  marketing  and  processing
operations  in 1999 versus  1998.  Loss  applicable  to common  shares was $11.3
million in 1999 versus  $48.0  million in 1998.  Loss per common share was $0.57
per share, basic and diluted,  in 1999 versus $2.27 per share, basic and diluted
in 1998.


Oil and Gas Operations:

     For the year 1999,  we reported  oil  production  of 1,307 Mbbls  (thousand
barrels)  and  gas  production  of  19,026  MMcf  (million  cubic  feet),  which
represents  a 15%  increase in oil volume and a 35%  increase in gas volume over
1998.  The  reported  production  in 1999 was  impacted  by the  acquisition  in
December  1998  of the  Spirit  76  properties  and in June  1999 of the  Vastar
properties.

     Prices received for oil and gas improved in 1999 over the depressed  levels
experienced in 1998. The oil price realized in 1999 after the effects of hedging
was $15.01 per barrel  versus the hedge  adjusted  price of $12.67 in 1998.  The
hedge  adjusted price for gas realized in 1999 was $2.16 per Mcf versus $2.02 in
1998.  This represents a 10% increase on a thousand cubic feet of gas equivalent
(Mcfe) basis in 1999 versus 1998. In 1999, hedging reduced the average oil price
realized  by $2.54  per  barrel  and had no  effect  on the  average  gas  price
realized.  On an equivalent unit basis, hedging reduced our sales price by $0.12
per Mcfe in 1999 and increased our sale price by $0.13 per Mcfe in 1998.

     As a result  of an  increase  in both  production  volumes  and oil and gas
prices  realized,  oil and gas revenues  increased  39% to $60.7 million in 1999
versus $43.6 million in 1998.

     Lifting  costs were $15.4  million in 1999,  an 8% increase over 1998. On a
per unit of production basis,  lifting costs decreased 16% to $0.57 per Mcfe due
primarily to the  acquisition  of properties  with lower average  lifting costs.
Production  taxes and other costs were $8.1 million in 1999, a 27% increase over
1998, while on a per unit of production basis, these costs decreased 3% to $0.30
per Mcfe.

     For 1999,  our gross margin from oil and gas  operations  increased  62% to
$37.1 million compared to $22.9 million in 1998, principally due to increases in
production and prices.  On a per unit of production  basis, the margin increased
31% to $1.39 per Mcfe in 1999 from $1.06 per Mcfe in 1998.

                                       32
<PAGE>

Gas Gathering, Marketing and Processing Operations:

     For 1999, our gathering system throughput was 18.5 MMcf per day versus 20.8
MMcf per day in 1998,  an 11% decrease due  primarily to the sale of a gathering
system  in  1999.  Gas  processing  throughput  was  21.5  MMcf  per day in 1999
versus15.7  MMcf per day in 1998,  a 37%  increase  due to the Vastar and Madill
acquisitions.

     For 1999,  the gross  margin we  realized  from  gathering,  marketing  and
processing  operations  was $2.3  million,  a 92%  increase  over the 1998 gross
margin of $1.2 million. Revenues were $8.2 million in 1999, an 18% increase over
1998  revenues of $7.0 million due to the Madill  plant and Vastar  acquisitions
and an improvement in product prices. Operating costs were $5.9 million in 1999,
a 2% increase over 1998 costs of $5.8 million.  The gross margin from  gathering
was $0.14 per Mcf in 1999,  a 27%  increase  over  1998.  Gas  processing  gross
margins  increased  129% to $0.16 per Mcf in 1999 over $0.07 per Mcf in 1998 due
to substantially improved processing economics.

Oil Field Services:

     Revenues from oil field services and international sales were $768 thousand
in 1999, a 13% decrease from revenues of $881 thousand in 1998,  principally due
to a  decrease  in oil field  management  services  provided  to third  parties.
Operating costs were $350 thousand in 1999, a $117 thousand  decrease over 1998.
The gross  operating  margin from these  activities  was $418,000 in 1999 versus
$414,000 in the 1998 period.

Other Income and Expenses:

     Depreciation  and depletion  expense was $22.1 million in 1999 versus $21.8
million in 1998.  Depreciation and depletion on oil and gas properties was $0.79
per  Mcfe in 1999  versus  $1.00  per  Mcfe in  1998,  a  decrease  of 21%.  The
improvement  in rates  was  partly  due to the  impairment  write-down  of $42.7
million to oil and gas properties in 1998.  Without the benefit of  improvements
in pricing  subsequent to December 31, 1998 we would have incurred an impairment
of $81.2 million.  While this write-down is not recoverable if prices  increase,
it has the effect of lowering our future depletion rates.

     We  recorded a gain on sale of $272  thousand in 1999 versus a loss on sale
of $52 thousand in 1998. General and  administrative  expense for 1999 decreased
3% to $2.9  million  from $3.0  million in 1998.  We recorded  equity in loss of
affiliate  of $103  thousand  in 1999  versus a loss of $116  thousand  in 1998,
relating to the  operations  of our  affiliate  engaged in natural gas marketing
operations.  Other income was $354 thousand in 1999 versus $624 thousand in 1998
due to a decrease in interest income.

     Interest expense  increased 21% to $22.1 million in 1999 from $18.2 million
in 1998 due to increased  levels of borrowing  under our revolving  credit lines
and an increase in floating interest rates.

     We recorded a benefit for deferred  income  taxes of $13.7  million in 1998
versus no tax benefit in 1999.  The  benefit  was  recorded in 1998 based on the
expectation  of or utilizing  net  operating  loss  carryovers  generating  this
benefit in future years.  No benefit was recorded in 1999 due to the uncertainty
of utilizing  additional loss carryovers due to annual  limitations on their use
caused by changes in ownership of our common stock.

     Dividends on preferred stock were $4.5 million in 1999 versus $875 thousand
in 1998.  The increase  was due to the issuance of $50.0  million of Series A 8%
Convertible preferred stock in 1999.

Liquidity and Capital Resources

     CASH FLOW AND WORKING CAPITAL. Net cash provided by operating activities in
2000,  1999 and  1998 was  $49.5  million,  $17.4  million  and  $13.7  million,
respectively.  The substantial increase in our operating cash flows in 2000 over
1999 and 1999 over 1998 is primarily  the result of higher  realized oil and gas
prices.  Our net working capital position at December 31, 2000 was $4.1 million.
On that date,  Magnum Hunter also had  available  $22.5 million under its senior
bank credit line, and Bluebird had $21.4 million available under its senior bank
credit line.

                                       33
<PAGE>

     INVESTING  ACTIVITIES.  Net cash  used in  investing  activities  was $20.0
million in 2000. We realized proceeds of $43.8 million from the sale of non-core
assets during the year, of which approximately $11.6 million was attributable to
Bluebird. Both the Company and Bluebird used these proceeds to repay senior bank
indebtedness.  We made cash  capital  expenditures  of $60.8  million  under our
capital budget during 2000, of which $19.1 million was attributable to Bluebird.
Our capital expenditures are discussed in further detail below. Additionally, we
made  investments  in two  unconsolidated  affiliates  totaling $2.6 million and
advanced  funds  totaling $1.4 million under  promissory  notes  receivable.  We
received  payments on promissory notes  receivable  totaling $1.0 million during
the year 2000.

     In 1999, net cash used in investing  activities  was $58.5  million,  which
included  proceeds from asset sales of $1.5 million and capital  expenditures of
$60.0 million.

     In 1998 we used $74.0  million in  investing  activities,  including  $70.2
million for capital  expenditures  and $3.9  million for other  assets.  We also
realized  $359 thousand in proceeds from sale of assets and made a $332 thousand
loan for a promissory note receivable.

     FINANCING  ACTIVITIES.  Net cash  used in  financing  activities  was $31.0
million in 2000.  We  borrowed a total of $101.1  million  under our senior bank
credit lines of which $11.5  million was  attributable  to  Bluebird.  We repaid
borrowings under our senior bank credit lines by $144.8 million,  of which $32.7
million was attributable to Bluebird. We received $60.0 million in cash from the
issuance of common and  preferred  stock,  net of offering  costs.  We paid $534
thousand of fees  related to  financing  activities.  We spent $25.0  million to
redeem our 1999  Series A  preferred  stock,  while  Bluebird  also spent  $10.5
million to acquire Magnum Hunter preferred and common stock. Cash dividends paid
were $10.2  million in 2000.  We loaned the ESOP $1.6  million to  purchase  our
common stock. Bluebird had a net decrease in cash of $325 thousand.

     In 1999,  net cash  provided by financing  activities  was $37.7 million We
borrowed a total of $106.8 million under our senior bank credit lines,  of which
$46.3  million was  attributable  to Bluebird.  We repaid  borrowings  under our
senior  bank  credit  lines by  $103.2  million,  of  which  $30.5  million  was
attributable  to  Bluebird.  We realized  proceeds  from  issuance of common and
preferred  stock of $46.3  million,  net of  offering  costs.  We also paid fees
related to financing activities of $1.6 million,  paid a short term note of $2.0
million,  loaned the ESOP $759  thousand,  loaned a shareholder  $123  thousand,
purchased  treasury stock for $1.7 million and paid preferred  dividends of $4.2
million. Bluebird had a net increase in cash of $1.7 million.

     In 1998, net cash provided by financing  activities  was $62.1 million.  We
borrowed a total of $80.0 million  under our senior bank credit lines,  of which
$26.0  million was  attributable  to Bluebird.  We repaid  borrowings  under our
senior bank credit lines by $10.6  million,  of which none was  attributable  to
Bluebird.  We also paid a short term note of $2.7 million,  loaned the ESOP $879
thousand, loaned a shareholder $480 thousand,  purchased treasury stock for $1.9
million  and paid  preferred  dividends  of $875  thousand.  Bluebird  had a net
increase in cash of $1.9 million.

     BLUEBIRD'S  CAPITAL  RESOURCES.  Internally  generated  cash  flow  and the
borrowing  capacity  under its senior  bank  credit  line are  Bluebird's  major
sources of liquidity.  From time to time,  Bluebird may also sell  properties in
order to increase  liquidity.  During 2000,  Bluebird realized proceeds of $11.6
million from property sales.

     On May 23, 2000,  Bluebird's commercial banks agreed to allow it to acquire
100% of Magnum Hunter's 1996 Series A convertible preferred stock at liquidation
value,  or $10 million,  and to purchase up to $500 thousand of Magnum  Hunter's
common stock. On December 7, 2000 the convertible preferred and the common stock
were sold to Magnum Hunter Production,  Inc. for cash proceeds of $10.5 million.
The proceeds  were used to pay down  Bluebird's  senior credit line. At December
31, 2000  Bluebird's  senior credit line borrowing base was set at $42.0 million
and  borrowings  under the  senior  credit  line  were  $20.6  million,  leaving
availability  of $21.4  million at that date. On February 28, 2001 the borrowing
base was reduced to $37.0 million.  We believe that this bank credit line, along
with cash flow from operations,  provides Bluebird with sufficient  liquidity to
meet interest  payments as well as carry out its capital  spending  budget plans
through 2001.

                                       34
<PAGE>

     MAGNUM  HUNTER'S  CAPITAL  RESOURCES.  The  following  discussion of Magnum
Hunter's  capital  resources refers to the Company and its affiliates other than
Bluebird,  whose capital resources were discussed  separately above.  Internally
generated cash flow and the borrowing capacity under its senior bank credit line
are the Company's major source of liquidity.  From time to time, the Company may
also sell  properties in order to increase  liquidity.  During 2000, the Company
realized proceeds of $32.2 million from property sales. In addition, the Company
may use other  sources of capital,  including  the issuance of  additional  debt
securities  or equity  securities,  as  sources  to fund  acquisitions  or other
specific  needs.  In the past,  the Company has accessed both public and private
capital  markets  to provide  liquidity  for  specific  activities  and  general
corporate purposes.

     During the year 2000,  the Company  realized  $60.0 million in net proceeds
from the issuance of its common stock, including $57.6 million from the exercise
of both its publically  traded and privately held warrants and $2.4 million from
the exercise of employee stock options.

     In December 2000 the Company used $10.0 million to purchase all of its 1996
Series A Convertible  preferred stock outstanding from Bluebird.  This preferred
stock was held by an affiliate  for possible  re-issue at a later date.  Also in
December  2000  the  Company  spent  $30.5  million  (including  a $5.5  million
redemption  premium)  to  redeem  50%  of  its  outstanding  1999  Series  A  8%
Convertible  preferred  stock.  In  January,  2001  the  remaining  50% of  this
preferred stock was converted to the Company's common stock by the holder at the
conversion  price of $5.25  per  share.  As a result  of these  preferred  stock
transactions,  the Company no longer has any  dividend  paying  preferred  stock
outstanding,  which will result in annual savings of approximately  $4.9 million
in dividends paid.

     The  Company's  borrowing  base under its senior bank credit line was $53.0
million  at  December  31,  2000 and its  borrowings  under this line were $30.5
million on that date,  leaving  availability of $22.5 million on that date. On a
semiannual basis, the borrowing base is redetermined by the banks based on their
review of the  Company's oil and gas reserves.  If the  outstanding  senior bank
debt exceeds the redetermined borrowing base, the Company must repay the excess.

     The Company's  internally  generated cash flow, results of operations,  and
financing for its operations are dependent on oil and gas prices. As a result of
substantial  increases in oil and gas prices in 2000 versus  1999,  our earnings
and cash flows in 2000 have been materially  increased  compared to 1999. To the
extent that oil and gas prices  decline,  the Company's  earnings and cash flows
may be adversely affected. However, the Company believes that its cash flow from
operations,  existing  working  capital and  availability  under its senior bank
credit line will be sufficient to meet interest payments and to fund the capital
expenditure budget for the year 2001.

     CAPITAL EXPENDITURES. During 2000, the Company's total capital expenditures
were $64.3  million.  Of the total,  $8.9 million was for  property  acquisition
costs,  of which $3.5 million  (paid in  restricted  common  stock) was spent to
acquire a net profits  interest in certain  properties.  Exploration  activities
accounted for $32.5 million, development activities accounted for $22.2 million,
and  additions  to other  assets  accounted  for $700  thousand  of the  capital
expenditures. As of December 31, 2000 the Company had total unproved oil and gas
property costs of $5.5 million, consisting of property acquisition costs of $3.9
million and exploratory costs of $1.6 million.

     For the year 2001, the Company has budgeted  approximately  $85 million for
exploration  and  development  activities.  The  Company  is  not  contractually
obligated to proceed with any of its budgeted capital  expenditures.  The amount
and allocation of future capital expenditures will depend on a number of factors
that are not  entirely  within the  Company's  control  or ability to  forecast,
including  drilling  results  and  changes in oil and gas  prices.  As a result,
actual capital expenditures may vary significantly from current expectations.

     In the normal course of business, the Company reviews opportunities for the
possible  acquisition  of oil and gas reserves and activities  related  thereto.
When  potential  acquisition   opportunities  are  deemed  consistent  with  the
Company's growth  strategy,  bids or offers in amounts and with terms acceptable
to the Company may be submitted. It is uncertain whether any such bids or offers
which may be submitted by the Company  from time to time will be  acceptable  to
the sellers. In the event of a future significant  acquisition,  the Company may
require additional financing in connection therewith.

                                       35
<PAGE>

     FORWARD-LOOKING STATEMENTS. This Form 10-K and the information incorporated
by reference  contain  statements that constitute  "forward-looking  statements"
within the meaning of Section 27A of the  Securities  Act and Section 21E of the
Securities Exchange Act. The words "expect", "project",  "estimate",  "believe",
anticipate,  "intend", "budget", "plan", "forecast", "predict" and other similar
expressions  are  intended  to  identify   forward-looking   statements.   These
statements  appear in a number of places and include  statements  regarding  our
plans,  beliefs,  or current  expectations,  including the plans,  beliefs,  and
expectations of our officers and directors.

     When considering any forward-looking statement, you should keep in mind the
risk factors that could cause our actual results to differ materially from those
contained in any forward-looking  statement.  Important factors that could cause
actual results to differ materially from those in the forward-looking statements
herein include the timing and extent of changes in commodity  prices for oil and
gas, operating risks and other risk factors as described in our Annual Report on
Form 10-K as filed with the Securities and Exchange Commission. Furthermore, the
assumptions  that  support  our   forward-looking   statements  are  based  upon
information  that  is  currently   available  and  is  subject  to  change.   We
specifically  disclaim all  responsibility  to publicly  update any  information
contained in a forward-looking statement or any forward-looking statement in its
entirety and therefore disclaim any resulting  liability for potentially related
damages.

     All  forward-looking  statements  attributable to Magnum Hunter  Resources,
Inc. are expressly qualified in their entirety by this cautionary statement.

Inflation and Changes in Prices

     During 2000, the Company experienced substantial increase in prices for oil
and gas compared to the previous  year.  The results of operations and cash flow
of the Company have been, and will continue to be, affected by the volatility in
oil and gas prices.  Should the Company experience a significant increase in oil
and gas prices that is sustained over a prolonged  period,  it would expect that
there would also be a corresponding increase in oil and gas finding costs, lease
acquisition costs, and operating expenses.  Periodically the Company enters into
futures,  options,  and swap contracts to reduce the effects of  fluctuations in
crude oil and gas prices.  It is the policy of the Company not to enter into any
such  arrangements  which  exceed 75% of the  Company's  oil and gas  production
during the next 12 months.

     The Company  markets  oil and gas for its own  account,  which  exposes the
Company  to  the  attendant  commodities  risk.  A  significant  portion  of the
Company's gas production is currently  sold to NGTS, LLC or end-users  either on
the spot market on a  month-to-month  basis at prevailing  spot market prices or
under  long-term  contracts  based on current  spot market  prices.  The Company
normally  sells  its  oil  under  month-to-month   contracts  to  a  variety  of
purchasers.

New Accounting Standard

     Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative  Instruments and Hedging  Activities"  (SFAS No. 133), as extended by
SFAS No. 137 (June 1999) and amended by SFAS No. 138 (June  2000),  is effective
for the Company beginning  January 1, 2001. SFAS No. 133 establishes  accounting
and reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. It requires
the recognition of derivatives in the balance sheet and the measurement of those
instruments at fair value.

     All derivatives  within the Company have been  identified  pursuant to SFAS
No. 133 requirements,  and the Company has designated,  documented, and assessed
hedging relationships.  The Company was obligated to four crude oil derivatives,
one natural gas derivative, and one interest rate derivative on January 1, 2001.
The Company has determined  that the interest rate  derivative  will not qualify
for  treatment as a fair value hedge as defined in the  Statement.  As a result,
the derivative  asset or liability  related to the interest rate derivative must
be  recorded  at fair  value on the  Company's  balance  sheet with an effect to
income.  The crude oil and natural gas derivatives  qualify as cash-flow hedges,
which  require the Company to record the  derivative  assets or  liabilities  at
their fair  value on its  balance  sheet  with an offset in other  comprehensive
income. Future hedge ineffectiveness on the cash-flow hedges will be recorded in
earnings.

     Adoption of this accounting  standard as of January 1, 2001 resulted in the
recognition of $179 thousand of derivative assets and $2.8 million of derivative
liabilities  with a cumulative  effect increase to income of $111 thousand after
tax and with a  cumulative  effect  decrease  to other  comprehensive  income of
approximately $1.8 million after-tax for the transition adjustment as of January
1, 2001.

                                       36
<PAGE>

Item 7A. Qualitative and Quantitative Disclosure About Market Risk

     The Company's  operations are exposed to market risks primarily as a result
of changes in  commodity  prices and  interest  rates.  The Company does not use
derivative  financial  instruments for speculative or trading  purposes.  Energy
swap agreements.  The Company produces,  purchases, and sells crude oil, natural
gas,  condensate,  and natural gas liquids. As a result, the Company's financial
results can be significantly impacted as these commodity prices fluctuate widely
in response to changing market forces. The Company has previously engaged in oil
and gas hedging  activities and intends to continue to consider  various hedging
arrangements  to realize  commodity  prices  which it considers  favorable.  The
Company  engages in futures  contracts  with certain of its  production  through
various contracts ("Swap Agreements"). The primary objective of these activities
is to protect against decreases in price during the term of the hedge.

     The Swap  Agreements  provide for separate  contracts  tied to the New York
Mercantile  Exchange  ("NYMEX")  light sweet oil and the Inside FERC natural gas
index price posting ("Index").  The Company has contracts which contain specific
contracted  prices  ("Swaps") that are settled  monthly based on the differences
between  the  contract  prices  and the  specified  Index  prices for each month
applied to the related  contract  volumes.  To the extent the Index  exceeds the
contract  price,  the Company  pays the spread,  and to the extent the  contract
price exceeds the Index price the Company receives the spread. In addition,  the
Company has combined  contracts which have agreed upon price floors and ceilings
("Costless  Collars").  To the  extent  the Index  price  exceeds  the  contract
ceiling,  the  Company  pays the spread  between the ceiling and the Index price
applied to the  related  contract  volumes.  To the extent  the  contract  floor
exceeds the Index,  the Company  receives the spread  between the contract floor
and the Index price applied to the related contract volumes.

     To the extent the Company  receives the spread  between the contract  floor
and the Index  price  applied to related  contract  volumes,  the  Company has a
credit risk in the event of nonperformance of the counterparty to the agreement.
The Company does not anticipate any material impact to its results of operations
as a result of nonperformance by such parties.

     At December 31, 2000, the Company had the following open contracts:
<TABLE>
<CAPTION>
<S>       <C>                  <C>                       <C>                    <C>
               Type               Volume/Month                Duration                 Avg. Price
          ---------------     ---------------------     ---------------------    ----------------------
Oil
------
          Collar.........            30,000 Bbl           Jan 01 - Jun 01          Floor - $25.00
                                                                                   Cap   - $33.50
          Collar.........            15,000 Bbl           Jan 01 - Jun 01          Floor - $25.00
                                                                                   Cap   - $34.35
          Collar.........            15,000 Bbl           Jan 01 - Jun 01          Floor - $25.00
                                                                                   Cap   - $35.50
          Collar.........            15,000 Bbl           Jan 01 - Jun 01          Floor - $25.00
                                                                                   Cap   - $36.80
Gas
------
          Collar.........           300,000 MMBtu         Jan 01 - Dec 01          Floor - $ 4.50
                                                                                   Cap   - $ 6.15
</TABLE>

     Based on future market prices at December 31, 2000,  the fair value of open
contracts  to the Company  was a liability  of $2.8  million.  If future  market
prices were to increase 10% from those in effect at December 31, 2000,  the fair
value of open contracts to the Company would be a liability of $3.7 million.  If
future  market  prices were to decline 10% from those in effect at December  31,
2000,  the fair value of the open  contracts to the Company would be a liability
of $1.7 million.

     The Company  currently intends to commit no more than 75% of its production
on a Bcfe  basis to such  arrangements  at any point in time.  A portion  of the
Company's oil and natural gas production  will be subject to price  fluctuations
unless the Company enters into additional hedging transactions.

                                       37
<PAGE>

Interest Rate Swaps

     On June 30, 1999, the Company entered into two interest rate swaps in order
to shift a  portion  of the  fixed  rate bond debt to  floating  rate  debt,  to
capitalize on what was perceived as a market  overreaction  to pending  interest
rate  increases by the Federal  Reserve and to  effectively  lower interest rate
expense over the following  twelve  months.  On June 1, 2000 one of the interest
rate swaps  terminated.  The following table reflects the terms of the remaining
swap.
<TABLE>
<CAPTION>
<S>                            <C>                   <C>                  <C>                   <C>
            Type                 Notional Amount      Termination Date         Pay Rate            Receive Rate
-----------------------------  -------------------   ------------------   ------------------   --------------------
 Pay Variable/Receive Fixed        $50,000,000            06/01/02          LIBOR + 3.34%           10% fixed
                                                                           through 05/31/00

                                                                            LIBOR + 3.69%
                                                                           from 06/01/00 to
                                                                               06/01/02
</TABLE>

     Based on future  market rates at December 31, 2000,  the fair value of open
contracts to the Company was an asset of $179,000.  If future  market rates were
to increase  10% from those in effect at December  31,  2000,  the fair value of
open contracts to the Company would be a liability of $314,000. If future market
rates were to decline 10% from those in effect at December  31,  2000,  the fair
value of the open contracts to the Company would be an asset of $603,000.

     Fixed and  Variable  Debt.  The  Company  uses fixed and  variable  debt to
partially finance budgeted expenditures.  These agreements expose the Company to
market risk related to changes in interest rates.

     The following  table  presents the carrying and fair value of the Company's
debt along with average  interest  rates.  Fair values are calculated as the net
present value of the expected cash flows of the  financial  instruments,  except
for the fixed rate senior notes,  which are valued at their last traded value in
2000.
<TABLE>
<CAPTION>
<S>                          <C>       <C>       <C>         <C>        <C>        <C>       <C>
   Expected Maturity Dates
        (in thousands)          2001      2002      2003      2004-2006    2007      Total   Fair Value
                              --------  --------  ---------   ---------  --------  --------- ----------
Variable Rate Debt:
Bank Debt with Recourse (a)...  $   -   $       -  $  30,500    $   -     $         $  30,500  $   30,500
Bank Debt without Recourse (b)  $   -   $  20,600  $       -    $   -     $         $  20,600  $   20,600
Fixed Rate Debt:
Senior Notes (c)..............  $   -   $       -  $       -    $   -     $140,000  $ 140,000  $  138,600
Bank Debt with Recourse (d)...  $  19   $      19  $       1    $   -     $      -  $      39  $       39
</TABLE>
------------

(a)  The average interest rate on the bank debt with recourse is 8.52%.
(b)  The average interest rate on the bank debt without recourse is 9.48%.
(c)  The interest rate on the senior notes is a fixed 10%.
(d)  The interest rate on the bank debt is a fixed 7.9%.

                                       38
<PAGE>

Item 8. Consolidated Financial Statements and Unaudited Supplemental Information


                   Index to Consolidated Financial Statements
                                                                            Page

 Independent Auditors' Report................................................F-1

 Financial Statements:
        Consolidated Balance Sheets at December 31, 2000 and 1999............F-2

        Consolidated Statements of Operations and Comprehensive Income for the
                 Years Ended December 31, 2000, 1999 and 1998................F-3

        Consolidated Statements of Stockholders' Equity for the
                 Years Ended December 31, 2000, 1999 and 1998................F-4

        Consolidated Statements of Cash Flows for the Years
                 Ended December 31, 2000, 1999 and 1998......................F-5

 Notes to Consolidated Financial Statements..................................F-6

 Supplemental Information (Unaudited).......................................F-30

                                       ii
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

Board of Directors and Stockholders
Magnum Hunter Resources, Inc.

     We have  audited the  accompanying  consolidated  balance  sheets of Magnum
Hunter  Resources,  Inc. and Subsidiaries as of December 31, 2000, and 1999, and
the related  consolidated  statements of operations  and  comprehensive  income,
stockholders'  equity,  and cash flows for each of the three years in the period
ended December 31, 2000. These financial  statements are the  responsibility  of
the Company's  management.  Our responsibility is to express an opinion on these
financial statements based on our audits.

     We conducted our audits in accordance  with  auditing  standards  generally
accepted in the United States of America.  Those standards  require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audits  provide  a
reasonable basis for our opinion.

     In our opinion,  the consolidated  financial  statements  referred to above
present  fairly,  in all material  respects,  the  financial  position of Magnum
Hunter  Resources,  Inc. and  Subsidiaries as of December 31, 2000 and 1999, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2000, in conformity with accounting  principles
generally accepted in the United States of America.



Deloitte & Touche LLP


Dallas, Texas
March 20, 2001


                                       F-1
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                            (in thousands of dollars)
<TABLE>
<CAPTION>
<S>                                                                             <C>                     <C>

                                                                                        December 31,      December 31,
                                                                                            2000              1999
                                                                                ----------------------------------------------------
                                     ASSETS
Current Assets
     Cash and cash equivalents..................................................    $           9         $   1,565
     Restricted cash ...........................................................            1,820             2,145
     Accounts receivable
          Trade, net of allowance of $50 and $166, respectively.................           30,442            10,203
          Due from affiliates...................................................              107                48
     Notes receivable from affiliate............................................              377               398
     Current portion of long-term notes receivable, net of allowance of $1,170
                      and $790, respectively....................................               50                57
     Prepaid and other..........................................................            2,033             1,296
                                                                                ----------------------------------------------------
           Total Current Assets.................................................           34,838            15,712
                                                                                ----------------------------------------------------
Property, Plant, and Equipment
     Oil and gas properties, full cost method
           Unproved.............................................................            5,534             3,567
           Proved...............................................................          367,822           349,510
     Pipelines..................................................................           12,581            12,462
     Other property.............................................................            2,459             1,964
                                                                                ----------------------------------------------------
     Total Property, Plant and Equipment........................................          388,396           367,503
           Accumulated depreciation, depletion, amortization and impairment.....         (127,864)         (102,308)
                                                                                ----------------------------------------------------
     Net Property, Plant and Equipment..........................................          260,532           265,195
                                                                                ----------------------------------------------------
Other Assets
     Deposits and other assets..................................................            6,570             5,663
     Investment in unconsolidated affiliates....................................            8,054             4,163
     Deferred tax asset ........................................................            5,618            13,289
                                                                                ----------------------------------------------------
                                                                                    $     315,612         $ 304,022
     Total Assets...............................................................====================================================

                      LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
     Trade payables and accrued liabilities.....................................    $      27,094         $  15,111
     Dividends payable..........................................................              169               552
     Suspended revenue payable..................................................            3,201             1,357
     Current income taxes payable...............................................              234                 -
     Current maturities of long-term debt, with recourse........................               19                 6
                                                                                ----------------------------------------------------
           Total Current Liabilities............................................           30,717            17,026
                                                                                ----------------------------------------------------
Long-Term Liabilities
     Long-term debt, with recourse, less current maturities.....................          170,520           193,000
     Long-term debt, non recourse, less current maturities......................           20,600            41,800
     Production payment liability...............................................              359               460
     Minority interest..........................................................                -               184
Commitments and Contingencies (Note 11)
Stockholders' Equity
     Preferred stock - $.001 par value; 10,000,000 shares authorized, 216,000
       designated as Series A; 80,000 issued and outstanding,
       liquidation amount $0....................................................                -                 -
       1,000,000 designated as 1996 Series A Convertible; 1,000,000 purchased
       and held for remarketing by subsidiary at December 31, 2000, 1,000,000
       issued and outstanding at December 31, 1999, liquidation
       amount $10,000,000.......................................................                1                 1
       50,000 designated as 1999 Series A 8% Convertible; 25,000 and 50,000
       issued and outstanding, respectively, liquidation amount $25,000,000 and
       $50,000,000, respectively................................................                -                 -
     Common Stock - $.002 par value; 100,000,000 shares authorized,
           30,705,398 and 21,738,320 shares issued, respectively................               61                43
     Additional paid-in capital.................................................          148,580           121,845
     Accumulated other comprehensive loss.......................................             (466)           (1,713)
     Accumulated deficit........................................................          (50,152)          (62,560)
     Receivable from stockholder................................................             (442)             (795)
     Unearned common stock in ESOP, at cost (680,282 and 537,515 shares,
       respectively)............................................................           (2,780)           (1,638)
                                                                                ----------------------------------------------------
                                                                                           94,802            55,183
     Treasury stock, at cost (455,063 and 1,512,719 shares of
       common stock, respectively)..............................................           (1,386)           (3,631)
                                                                                ----------------------------------------------------
     Total Stockholders' Equity.................................................           93,416            51,552
                                                                                ----------------------------------------------------
     Total Liabilities and Stockholders' Equity.................................    $     315,612         $ 304,022
                                                                                ====================================================
</TABLE>
     The accompanying notes are an integral part of these consolidated financial
statements.

                                      F-2
<PAGE>

                 Magnum Hunter Resources, Inc. and Subsidiaries
         Consolidated Statements of Operations and Comprehensive Income
             (in thousands of dollars, except for per share amounts)
<TABLE>
<CAPTION>
<S>                                                             <C>              <C>            <C>
                                                                                     For the Years Ended
                                                                                        December 31,
                                                              ----------------------------------------------------------------------
                                                                         2000            1999             1998
                                                              ----------------------------------------------------------------------
Operating Revenues:
   Oil and gas sales..........................................  $      106,052   $       60,673  $       43,565
   Gas gathering, marketing and processing....................          20,010            8,185           6,954
   Oil field services.........................................           1,448              768             881
                                                              ----------------------------------------------------------------------
         Total Operating Revenues.............................         127,510           69,626          51,400
                                                              ----------------------------------------------------------------------
Operating Costs and Expenses:
   Oil and gas production lifting costs.......................          16,401           15,431          14,265
   Production taxes and other costs...........................          12,558            8,144           6,417
   Gas gathering, marketing and processing....................          15,685            5,870           5,750
   Oil field services.........................................             903              350             467
   Depreciation, depletion and amortization...................          25,556           22,072          21,757
   Provision for non-cash impairment of oil and gas reserves..               -                -          42,745
   (Gains) losses on sale of assets...........................             (28)            (272)             52
   General and administrative.................................           6,106            2,919           2,961
                                                              ----------------------------------------------------------------------
         Total Operating Costs and Expenses...................          77,181           54,514          94,414
                                                              ----------------------------------------------------------------------
Operating Profit (Loss).......................................          50,329           15,112         (43,014)
   Equity in earnings (loss) of affiliate.....................           1,307             (103)           (116)
   Other income...............................................             477              354             624
   Interest expense...........................................         (22,298)         (22,103)        (18,207)
                                                              ----------------------------------------------------------------------
Income (loss) before income tax and minority interest.........          29,815           (6,740)        (60,713)
   Provision for income tax (expense) benefit
      Current.................................................            (234)               -               -
      Deferred................................................          (7,321)               -          13,670
                                                              ----------------------------------------------------------------------
         Total provision for income (tax) benefit.............          (7,555)               -          13,670
                                                              ----------------------------------------------------------------------
Income (loss) before minority interest........................          22,260           (6,740)        (47,043)
   Minority interest in subsidiary loss.......................               -              (86)            (37)
                                                              ----------------------------------------------------------------------
Net Income (Loss).............................................          22,260           (6,826)        (47,080)
   Dividends Applicable to Preferred Stock....................          (9,708)          (4,509)           (875)
                                                              ----------------------------------------------------------------------
Income (Loss) Applicable to Common Shares.....................  $       12,552   $      (11,335) $      (47,955)
                                                              ======================================================================
Net Income (Loss).............................................  $       22,260   $       (6,826) $      (47,080)
Other Comprehensive Income (Loss), net of tax
   Unrealized Gain (Loss) on Investments......................           1,247             (405)         (1,308)
                                                              ----------------------------------------------------------------------
Comprehensive Income (Loss)...................................  $       23,507   $       (7,231) $      (48,388)
                                                              ======================================================================

Income (Loss) per Common Share - Basic........................  $         0.60   $        (0.57) $        (2.27)
                                                              ======================================================================
Income (Loss) per Common Share - Diluted......................  $         0.51   $        (0.57) $        (2.27)
                                                              ======================================================================
Common Shares Used in Per Share Calculation
   Basic .....................................................      20,856,854       19,743,738      21,151,442
                                                              ======================================================================
   Diluted ...................................................      32,834,270       19,743,738      21,151,442
                                                              ======================================================================
</TABLE>
     The accompanying notes are an integral part of these consolidated financial
statements.

                                      F-3
<PAGE>

                 Magnum Hunter Resources, Inc. and Subsidiaries
                 Consolidated Statements of Stockholders' Equity
             For the Periods Ended December 31, 2000, 1999 and 1998
                             (dollars in thousands)
<TABLE>
<CAPTION>
<S>                                             <C>         <C>        <C>        <C>         <C>          <C>

                                                 Preferred Stock          Common Stock          Treasury Stock
                                                Shares      Amount     Shares      Amount     Shares       Amount
                                               ----------------------------------------------------------------------
Balance at December 31, 1997 .................. 1,080,000   $  1       21,738,320 $  43         (538,633)  $      (1)
  Common Stock contributed to 401(k) plan .....                                                   12,813           -
  Exercise of employees' common stock options .                                                   96,913           -
  Purchase of treasury stock ..................                                                 (625,600)     (1,908)
  Dividends declared on preferred stock .......
  Net loss.....................................
  Unrealized loss on investment ...............
  Loan to stockholder..........................
  Unearned shares in ESOP......................
                                               ----------------------------------------------------------------------
Balance at December 31, 1998................... 1,080,000   $  1       21,738,320 $  43       (1,054,507)  $  (1,909)
                                               ----------------------------------------------------------------------
  Issuance of 1999 Series A 8% Convertible
    stock, net of offering costs ..............    50,000      -
  Fees paid on issuance of warrants............
  Common Stock contributed to 401(k) plan .....                                                   41,115           -
  Exercise of employees' common stock options .                                                  102,145           -
  Costs associated with release of shares
    from ESOP..................................
  Purchase of treasury stock ..................                                                 (601,472)     (1,722)
  Dividends declared on preferred stock .......
  Net loss ....................................
  Unrealized loss on investment ...............
  Loan to stockholder..........................
  Unearned shares in ESOP......................
                                               ----------------------------------------------------------------------
Balance at December 31, 1999................... 1,130,000   $  1       21,738,320 $  43       (1,512,719)  $  (3,631)
  Purchase of 1996 Series A convertible
    preferred stock by subsidiary..............
  Redemption of 1999 Series A 8% convertible
          preferred stock......................   (25,000)
  Purchase of treasury stock...................                                                 (129,032)       (500)
  Exercise of employees' common stock options..                           528,942     1          127,450          77
  Exercise of warrants, net of expenses........                         8,438,136    17          702,272       1,588
  Issuance of common stock for property........                                                  356,966       1,080
  Costs associated with release of shares
    from ESOP..................................
  Deferred tax benefit on exercise of employee
          stock options........................
  Net income...................................
  Dividends on preferred stock.................
  Unrealized gain on investment................
  Repayment of stockholder loan................
  Unearned shares in ESOP......................
                                               ----------------------------------------------------------------------
Balance at December 31, 2000................... 1,105,000   $  1       30,705,398 $  61         (455,063)  $  (1,386)
                                               ======================================================================
</TABLE>

<TABLE>
<CAPTION>
<S>                                             <C>           <C>               <C>             <C>            <C>          <C>
                                                Additional    Accumulated Other                 Receivable      Unearned Shares in
                                                 Paid-In        Comprehensive   Accumulated        from                 ESOP
                                                 Capital        Income (Loss)     Deficit       Stockholder    Shares       Amount
                                               -------------------------------------------------------------------------------------
Balance at December 31, 1997 .................. $  80,763     $         -       $    (8,654)    $        -            -     $     -
  Common Stock contributed to 401(k) plan .....        66
  Exercise of employees' common stock options .        78
  Purchase of treasury stock ..................
  Dividends declared on preferred stock .......      (875)
  Net loss.....................................                                     (47,080)
  Unrealized loss on investment ...............                    (1,308)
  Loan to stockholder..........................                                                       (672)
  Unearned shares in ESOP......................                                                                (250,423)       (756)
                                               -------------------------------------------------------------------------------------
Balance at December 31, 1998................... $  80,032     $    (1,308)      $   (55,734)    $     (672)    (250,423)    $  (756)
                                               -------------------------------------------------------------------------------------
  Issuance of 1999 Series A 8% Convertible
    stock, net of offering costs ..............    46,260
  Fees paid on issuance of warrants............      (133)
  Common Stock contributed to 401(k) plan .....       123
  Exercise of employees' common stock options .        74
  Costs associated with release of
    shares from ESOP...........................        (2)
  Purchase of treasury stock ..................
  Dividends declared on preferred stock .......    (4,509)
  Net loss ....................................                                      (6,826)
  Unrealized loss on investment ...............                      (405)
  Loan to stockholder..........................                                                       (123)
  Unearned shares in ESOP......................                                                                (287,092)       (882)
                                               -------------------------------------------------------------------------------------

Balance at December 31, 1999................... $ 121,845     $    (1,713)      $   (62,560)    $     (795)    (537,515)    $(1,638)
  Purchase of 1996 Series A convertible
    preferred stock by subsidiary..............   (10,035)
  Redemption of 1999 Series A 8% convertible
          preferred stock......................   (25,000)
  Purchase of treasury stock...................
  Exercise of employees' common stock options..     2,335
  Exercise of warrants, net of expenses........    55,952
  Issuance of common stock for property........     2,401
  Costs associated with release of
    shares from ESOP...........................       672
  Deferred tax benefit on exercise of employee
          stock options........................       410
  Net income...................................                                      22,260
  Dividends on preferred stock.................                                      (9,852)
  Unrealized gain on investment................                     1,247
  Repayment of stockholder loan................                                                        353
  Unearned shares in ESOP......................                                                                (142,767)     (1,142)
                                               -------------------------------------------------------------------------------------
Balance at December 31, 2000................... $ 148,580     $      (466)      $   (50,152)    $     (442)    (680,282)    $(2,780)
                                               =====================================================================================
</TABLE>
     The accompanying notes are an integral part of these consolidated financial
statements.

                                      F-4
<PAGE>

                 Magnum Hunter Resources, Inc. and Subsidiaries
                      Consolidated Statements of Cash Flows
                                 (in thousands)
<TABLE>
<CAPTION>
<S>                                                                                     <C>             <C>             <C>
                                                                                                  For the Years Ended
                                                                                                     December 31,
                                                                                   -------------------------------------------------
                                                                                              2000             1999            1998
                                                                                   -------------------------------------------------
CASH FLOW FROM OPERATING ACTIVITIES:
   Net income (loss)...............................................................     $    22,260      $    (6,826)   $   (47,080)
   Adjustments to reconcile net income (loss) to cash
     provided by operating activities
         Depreciation, depletion and amortization..................................          25,556           22,072         21,757
         Impairment of oil and gas properties .....................................               -                -         42,745
         Amortization of financing fees............................................           1,318            2,091            793
         Increase in allowance for doubtful accounts...............................             464                -            591
         Deferred income taxes.....................................................           7,321                -        (13,670)
         Equity in (income) loss of unconsolidated affiliate.......................          (1,307)             103            116
         Minority interest expense.................................................               -               86             37
         Cost of shares released from ESOP.........................................             448              151            123
         Excess of fair value over cost of shares released from ESOP...............             672               (2)             -
         (Gain) Loss on sale of assets.............................................             (28)            (272)            52
         Other.....................................................................               -                -            (83)
         Changes in certain assets and liabilities
                  Accounts and notes receivable....................................         (20,378)          (4,660)         6,859
                  Other current assets.............................................            (737)             281           (278)
                  Accounts payable and accrued liabilities.........................          13,827            4,411          1,726
                  Current income taxes payable.....................................             234                -              -
                  Minority interest liability......................................            (184)               -              -
                                                                                   -------------------------------------------------
   Net Cash Provided By Operating Activities.......................................          49,466           17,435         13,688
                                                                                   -------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
   Proceeds from sale of assets....................................................          43,770            1,499            359
   Additions to property and equipment.............................................         (60,830)         (59,968)       (70,187)
   Increase in deposits and other assets...........................................               -                -         (3,878)
   Loan made for promissory note receivable........................................          (1,370)               -           (332)
   Payments received on promissory note receivable ................................           1,012                -             28
   Investment in unconsolidated affiliate..........................................          (2,590)               -              -
                                                                                   -------------------------------------------------
   Net Cash Used In Investing Activities...........................................         (20,008)         (58,469)       (74,010)
                                                                                   -------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
   Proceeds from the issuance of long-term debt and production payment.............         101,056          106,800         80,000
   Fees paid related to financing activities.......................................            (534)          (1,603)             -
   Payments of principal on long-term debt and production payment..................        (144,824)        (103,186)       (10,633)
   Payment of short-term notes payable ............................................               -           (2,000)        (2,699)
   Loan repaid by (made to) stockholder............................................             353             (123)          (480)
   Loan to ESOP....................................................................          (1,590)            (759)          (879)
   Payment of fees on issuance of warrants and preferred stock.....................               -             (133)             -
   Proceeds from issuance of common and preferred stock, net of offering costs.....          59,970           46,334             78
   Purchase of 1996 Series A preferred stock by subsidiary.........................         (10,035)               -              -
   Redemption of 1999 Series A preferred stock.....................................         (25,000)               -              -
   Purchase of treasury stock .....................................................            (500)          (1,722)        (1,908)
   Decrease (increase) in restricted cash for payment of notes payable ............             325           (1,686)          (459)
   Dividends paid..................................................................         (10,235)          (4,176)          (875)
                                                                                   -------------------------------------------------
   Net Cash (Used In) Provided By Financing Activities.............................         (31,014)          37,746         62,145
                                                                                   -------------------------------------------------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS...............................          (1,556)          (3,288)         1,823
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.....................................           1,565            4,853          3,030
                                                                                   -------------------------------------------------
CASH AND CASH EQUIVALENTS AT END OF YEAR...........................................     $         9     $      1,565    $     4,853
                                                                                   =================================================
</TABLE>
     The accompanying notes are an integral part of these consolidated financial
statements.

                                      F-5
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Nature of Operations

     Magnum Hunter Resources,  Inc. (the "Company"),  is incorporated  under the
laws of the state of Nevada. The Company and its subsidiaries are engaged in the
acquisition, operation and development of oil and gas properties, the gathering,
processing,  transmission,  and marketing of natural gas and natural gas liquids
and  providing  management  and  advisory  consulting  services  on oil  and gas
properties for third  parties.  In conjunction  with the above  activities,  the
Company owns and operates oil and gas properties in six states, predominantly in
the Southwest  region of the United  States.  In addition,  the Company owns and
operates  two  gathering  systems  located  in Texas  and  Oklahoma  and owns an
interest in three natural gas processing  plants located in Texas,  Oklahoma and
Arkansas.

Consolidation

     The accompanying  consolidated financial statements include the accounts of
the Company and its existing  wholly-owned  subsidiaries,  Bluebird Energy, Inc.
("Bluebird"),  Gruy Petroleum Management Company ("Gruy"), Hunter Gas Gathering,
Inc.,  Inesco  Corporation,  Magnum  Hunter  Production,  Inc.,  Midland  Hunter
Petroleum  Limited  Liability  Company,  SPL Gas  Marketing,  Inc.  The  Company
consolidates on a pro rata basis its approximately 41% ownership of TEL Offshore
Trust.  The Company  accounts for its  investment in NGTS,  LLC under the equity
method.  All  significant  intercompany  accounts  and  transactions  have  been
eliminated in  consolidation.  Certain  reclassifications  have been made to the
consolidated  financial statements of the prior year to conform with the current
presentation.

     The Company is a holding  company with no significant  assets or operations
other than its investments in its subsidiaries. The wholly-owned subsidiaries of
the Company,  except for  Bluebird,  are direct  Guarantors of the Company's 10%
Senior Notes and have fully and unconditionally  guaranteed the Notes on a joint
and  several  basis.  The  Guarantors  comprise  all of the direct and  indirect
subsidiaries of the Company (other than Bluebird), and the Company has presented
separate  condensed  consolidating  financial  statements and other  disclosures
concerning each Guarantor and Bluebird (See Note 17). Except for Bluebird, there
is no restriction on the ability of consolidated or unconsolidated  subsidiaries
to  transfer  funds to the  Company  in the form of cash  dividends,  loans,  or
advances.

     Bluebird was formed in December 1998, for the purpose of acquiring  certain
assets of  Spirit  76 (see  "Acquisitions").  As part of the  capitalization  of
Bluebird,  the Company  contributed to Bluebird  1,840,271 units of TEL Offshore
Trust. Bluebird, as an "unrestricted subsidiary" as defined under certain credit
agreements,  is neither a guarantor of the  Company's  10% Senior Notes due 2007
nor  can  it be  included  in  determining  compliance  with  certain  financial
covenants under the Company's credit agreements.

Cash and Cash Equivalents

     The Company  considers all highly liquid debt instruments  purchased with a
maturity of three  months or less to be cash  equivalents.  The Company has cash
deposits in excess of federally insured limits.

Restricted Cash

     Restricted cash is the cash balance of Bluebird. Cash funds of Bluebird are
not  permitted  to be  commingled  with  funds of  Magnum  Hunter  or its  other
subsidiaries or affiliates.  Such funds cannot be dividended or loaned to Magnum
Hunter or its other  subsidiaries  or affiliates but must be used to satisfy the
cash  requirements  of Bluebird,  including  payment of  Bluebird's  outstanding
borrowings.

                                       F-6
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

Investments

     The  Company  follows  accounting  procedures  according  to  Statement  of
Financial   Accounting  Standards  ("SFAS")  No.  115,  Accounting  for  Certain
Investments  in Debt and  Equity  Securities.  Under this  standard,  the equity
securities  held by the Company that have readily  determinable  fair values are
classified as current or non-current assets, available-for-sale and are measured
at fair value. Unrealized gains and losses for these investments are reported as
comprehensive  income and  included  as a separate  component  of  stockholders'
equity.

     At December 31, 2000 and 1999, the Company's available-for-sale  securities
were classified as non-current assets and included in deposits and other assets.
At December 31,  2000,  the  securities  had a cost basis of  $2,762,000,  gross
unrealized losses reported in accumulated other comprehensive income of $507,000
($466,000 net of income tax benefit) and had a fair market value of  $2,255,000.
At December 31,  1999,  the  securities  had a cost basis of  $2,762,000,  gross
unrealized  losses  reported  in  accumulated  other  comprehensive   income  of
$2,514,000 ($1,713,000 net of income tax benefit) and had a fair market value of
$248,000.

     During  2000,  the  Company  acquired a minority  ownership  interest  in a
privately  held company  that  provides  remote data  collection  and  web-based
monitoring  services for the energy industry.  The total invested by the Company
in 2000 was $2.5 million,  and the investment was carried at cost on the balance
sheet at December 31, 2000.

Suspended Revenues

     Suspended  revenue  interests  represent oil and gas sales payable to third
parties largely on properties  operated by the Company.  The Company distributes
such  amounts  to third  parties  upon  receipt  of  signed  division  orders or
resolution of other legal matters.

Oil and Gas Producing Operations

     Magnum Hunter  follows the full-cost  method of accounting  for oil and gas
properties. Accordingly, all costs associated with acquisition,  exploration and
development of oil and gas reserves,  including directly related overhead costs,
are capitalized. Internal costs that directly relate to acquisition, exploration
and development  activities that were  capitalized  totaled $600,000 for each of
the years ended December 31, 2000, 1999 and 1998,  respectively.  The balance of
capitalized  costs  included  in oil and gas  properties  for  the  years  ended
December  31,  2000 and  1999  were  $2,679,000  and  $2,079,000,  respectively.
Management  believes  that the basis it uses to determine the amount of internal
costs capitalized is appropriate.

     All capitalized  costs of oil and gas  properties,  including the estimated
future  costs  to  develop  proved  reserves  and  estimated  dismantlement  and
abandonment   costs,   net   of   salvage   values,   are   amortized   on   the
unit-of-production  method using  estimates of proved  reserves.  Costs directly
associated  with the  acquisition  and  evaluation  of unproved  properties  are
excluded from the amortization base until the related  properties are evaluated.
Such unproved  properties  are assessed for impairment at least annually and any
provision for  impairment is  transferred  to the full-cost  amortization  base.
Sales of oil and gas properties,  including consideration received from sales or
transfers  of  properties  in  connection  with   partnerships,   joint  venture
operations or drilling  arrangements,  are credited to the full-cost pool unless
the sale would have a significant effect on the amortization  rate.  Abandonment
of properties is accounted  for as an  adjustment to  capitalized  costs with no
loss recognized.

                                       F-7
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     A summary of the unproved  properties  excluded from oil and gas properties
being  amortized at December  31, 2000 and the year in which they were  incurred
follows:

                                             December 31, 2000
                                                Incurred In
                                               (in thousands)
                               -------------------------------------------------
                               Prior      1998       1999       2000       Total
                               -----      ----       ----       ----       -----
Property Acquisition Costs...  $   -  $   1,397  $   1,485  $   1,080  $   3,962
Exploration Costs............      -          -          -      1,572      1,572
                               -------------------------------------------------
     Total...................  $   -  $   1,397  $   1,485  $   2,652  $   5,534
                               =================================================

     Costs are transferred into the amortization base on an ongoing basis as the
projects  are  evaluated  and proved  reserves  are  established  or  impairment
determined.  Pending  determination of proved reserves attributable to the above
costs, the Company cannot assess the future impact on the amortization rate.

     The  capitalized  costs are subject to a "ceiling  test,"  which  generally
limits such costs less  accumulated  amortization  and related  deferred  income
taxes to the  aggregate of the  estimated  present  value of future net revenues
from proved  reserves  discounted at ten percent  based on current  economic and
operating  conditions less income tax effects related to the differences between
the  book and tax  basis  of the oil and gas  properties.  The  ceiling  test is
performed on a quarterly basis. At December 31, 1998, the Company wrote down the
costs of its oil and gas  properties  by  $42,745,000,  pursuant  to the ceiling
limitation,  using certain  improvements in pricing experienced after year- end.
The effect of this  write-down was a non-cash  charge to earnings of $42,745,000
and  an  increase  in  accumulated  depreciation,  depletion,  amortization  and
impairment for the same amount.  Without the benefit of  improvements in pricing
after  December 31,  1998,  the Company  would have  incurred an  impairment  of
$81,154,000. The Company experienced no impairment in 1999 or 2000.

     All costs  relating  to  production  activities  are  charged to expense as
incurred.

     Amortization  expense per thousand cubic feet  equivalent was $0.89,  $0.79
and $1.00 for the years ended December 31, 2000, 1999 and 1998, respectively.

Derivative Instruments

     The Company's  product price and interest hedging  activities are described
in Note 13 to the  consolidated  financial  statements.  The Company enters into
swaps,  futures,  options and other derivative  contracts to hedge the impact of
market  fluctuations  in gas and oil  prices on  anticipated  future oil and gas
production.  The Company is exposed to price risk  related to its future oil and
gas  production and enters into these  instruments to manage this exposure.  The
Company  hedges  only  those  anticipated  future  transactions  for  which  the
significant  characteristics  and expected terms are identified and are probable
of  occurring.  The Company  defers the impact of changes in the market value of
the contracts  that serve as hedges until the related  transaction is completed.
Any derivative  instruments that do not meet this criteria are marked-to-market.
The Company does not hold or issue derivative instruments for trading purposes.

Pipelines and Processing Plant

     Pipelines  and  processing  plant  are  carried  at cost.  Depreciation  is
provided  using the  straight-line  method over an  estimated  useful life of 15
years.  Gain or loss on  retirement  or sale or other  disposition  of assets is
included  in results of  operations  in the period of  disposition.  The Company
reviews  the  carrying  value  of  pipelines  and  processing  plant  and  other
long-lived  assets  (other  than oil and gas  assets  accounted  for  under  the
full-cost method) for impairment whenever events and circumstances indicate that
the carrying value of an asset may not be recoverable  from the estimated future
cash flows  expected to result from its use and eventual  disposition.  In cases
where the  undiscounted  expected  future cash flows are less than the  carrying
value, an impairment loss is recognized equal to an amount by which the carrying
value exceeds the fair value of assets.

                                       F-8
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

Other Property

     Other property and equipment are carried at cost.  Depreciation is provided
using the straight-line  method over estimated useful lives ranging from five to
ten years.  Gain or loss on retirement or sale or other disposition of assets is
included in results of operations in the period of disposition.

Other Oil and Gas Related Services

     Other oil and gas related  services consist largely of fees earned from the
Company's  operation of oil and gas properties for third parties.  Such fees are
recognized in the month the service is provided.

     Magnum Hunter does not recognize  income in connection with drilling,  well
service or other services  provided in connection with oil and gas properties in
which the Company holds an ownership or other economic interest to the extent of
the Company's  interest.  Any proceeds received for services  performed that are
not recognized as income are credited to the full cost pool.

Income Taxes

     The Company files a consolidated  federal  income tax return.  Income taxes
are  provided  for the tax effects of  transactions  reported  in the  financial
statements  and consist of taxes  currently due, if any, plus net deferred taxes
related primarily to differences between the basis of assets and liabilities for
financial  and  income  tax  reporting.  Deferred  tax  assets  and  liabilities
represent the future tax return  consequences  of those  differences  which will
either be taxable or deductible when the assets and liabilities are recovered or
settled.  Deferred tax assets include  recognition of operating  losses that are
available to offset future  taxable income and tax credits that are available to
offset  future  income  taxes.  Valuation  allowances  are  recognized  to limit
recognition  of deferred tax assets where  appropriate.  Such  allowances may be
reversed when  circumstances  provide evidence that the deferred tax assets will
more likely than not be realized.

New Accounting Standard

     Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative  Instruments and Hedging  Activities"  (SFAS No. 133), as extended by
SFAS No. 137 (June 1999) and amended by SFAS No. 138 (June  2000),  is effective
for the Company beginning  January 1, 2001. SFAS No. 133 establishes  accounting
and reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. It requires
the recognition of derivatives in the balance sheet and the measurement of those
instruments at fair value.

     All derivatives  within the Company have been  identified  pursuant to SFAS
No. 133 requirements,  and the Company has designated,  documented, and assessed
hedging relationships.  The Company was obligated to four crude oil derivatives,
one natural gas derivative, and one interest rate derivative on January 1, 2001.
The Company has determined  that the interest rate  derivative  will not qualify
for  treatment as a fair value hedge as defined in the  Statement.  As a result,
the derivative  asset or liability  related to the interest rate derivative must
be  recorded  at fair  value on the  Company's  balance  sheet with an offset to
income.  The crude oil and natural gas derivatives  qualify as cash-flow hedges,
which  require the Company to record the  derivative  assets or  liabilities  at
their fair  value on its  balance  sheet  with an offset in other  comprehensive
income. Future hedge ineffectiveness on the cash-flow hedges will be recorded in
earnings.

     Adoption of this accounting  standard as of January 1, 2001 resulted in the
recognition  of $179,000 of  derivative  assets and $2.8  million of  derivative
liabilities  with a cumulative  effect increase to income of $111 thousand after
tax and with a cumulative effect decrease to other comprehensive  income of $1.8
million after-tax for the transition adjustment as of January 1, 2001.

                                       F-9
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

Income or Loss Per Common Share

     Basic net income or loss per common  share is computed by dividing  the net
income or loss  attributable  to common  stockholders  by the  weighted  average
number of shares of common  stock  outstanding  during the  period.  Diluted net
income or loss per  common  share is  calculated  in the same  manner,  but also
considers the impact to net income and common shares for the potential  dilution
from  stock  options,  stock  warrants  and any  other  outstanding  convertible
securities.

     The following table reconciles the numerators and denominators  used in the
computations  of both  basic  and  diluted  EPS as  required  by SFAS  No.  128,
"Earnings per Share":
<TABLE>
<CAPTION>
<S>                              <C>          <C>        <C>     <C>        <C>           <C>      <C>          <C>       <C>
                                       For the Year Ended                For the Year Ended                For the Year Ended
                                        December 31, 2000                 December 31, 1999                 December 31, 1998
                               -----------------------------------------------------------------------------------------------------
                                                            Per                              Per                               Per
                                  Income        Shares     Share     Loss       Shares      Share      Loss       Shares      Share
                                (Numerator) (Denominator) Amount (Numerator) (Denominator) Amount  (Numerator) (Denominator)  Amount
                                ----------------------------------------------------------------------------------------------------
Net Income (Loss)..............  $22,260,000                     $ (6,826,000)                      $(47,080,000)
     Less: Preferred Stock
           dividendse..........   (9,708,000)                      (4,509,000)                          (875,000)
                                ----------------------------------------------------------------------------------------------------
Basic EPS
Income (Loss) available to
     common stockholders.......   12,552,000    20,856,854 $0.60  (11,335,000)  19,743,738  $(0.57)  (47,955,000) 21,151,442 $(2.27)
Effect of dilutive securities
   Warrants....................            -       571,623                  -            -                     -           -
   Options.....................            -     1,247,063                  -            -                     -           -
   Convertible preferred stock.    4,312,000    10,158,730                  -            -                     -           -
Diluted EPS
Income (Loss) available to
     common stockholders and   -----------------------------------------------------------------------------------------------------
     assumed conversions......   $16,864,000    32,834,270 $0.51 $(11,335,000)  19,743,738  $(0.57) $(47,955,000) 21,151,442 $(2.27)
                               =====================================================================================================
</TABLE>


     The warrants, options, and convertible preferred stock were not included in
the computation of diluted earnings per share in 1999 and 1998 since the Company
incurred  a net  loss for the year and any  effect  would be  anti-dilutive.  At
December 31, 2000, 73,126 shares of stock under warrants and 3,455,337 shares of
stock  under  options  were  excluded  from the  diluted  net  income  per share
computation  as the  exercise  price  exceeded  the average  market price of the
Company's  common  stock.  At December  31,  1998,  the Company had  outstanding
141,000  warrants  at a  weighted  average  exercise  price of $4.75 per  share,
2,661,587  options at a weighted  average exercise price of $3.90 per share, and
1,000,000  shares of preferred  stock  convertible  to common stock at $5.25 per
share. At December 31, 1999, the Company had outstanding  10,583,149 warrants at
a weighted  average  exercise price of $6.49 per share,  3,866,092  options at a
weighted  average  exercise  price of $3.57 per share  and  1,050,000  shares of
preferred  stock  convertible to common stock at a weighted  average  conversion
price of $5.25 per share.  At December  31,  2000,  the Company had  outstanding
644,749  warrants  at a  weighted  average  exercise  price of $6.75 per  share,
4,702,400  options at a weighted  average exercise price of $4.97 per share, and
25,000  shares of  preferred  stock  convertible  to common  stock at a weighted
average conversion price of $5.25 per share.

Use of Estimates and Certain Significant Estimates

     The  preparation of the Company's  financial  statements in conformity with
accounting  principles  generally  accepted  in the  United  States  of  America
requires the Company's  management to make estimates and assumptions that affect
the amounts  reported in these  financial  statements  and  accompanying  notes.
Actual results could differ from those  estimates.  Significant  assumptions are
required in the  valuation  of proved oil and gas  reserves,  which as described
above may affect the amount at which oil and gas properties are recorded.  It is
at least  reasonably  possible those estimates could be revised in the near term
and those revisions could be material.

                                      F-10
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

Treasury Stock

     The  Company  may  repurchase  shares of common  stock in stock  repurchase
programs.  The Company's  repurchases  of shares of common stock are recorded as
Treasury Stock at cost and result in a reduction of Stockholders'  Equity.  When
treasury shares are reissued,  the Company uses a first-in  first-out method and
the difference  between  repurchase  cost and reissuance  price is treated as an
adjustment to paid-in capital.

NOTE 2 -- ACQUISITIONS

     On January 28, 1998, the Company  commenced a cash purchase offer for Units
of TEL Offshore  Trust.  Previous to the offer,  the Company owned 161,500 Units
representing  3.4% of the  Units  outstanding.  As  amended,  the  offer  was to
purchase  between  forty  percent  (40%) and sixty  percent (60%) of the Trust's
outstanding  Units at $5.50 per Unit. On March 27, 1998,  the Company  purchased
1,745,353  Units  pursuant to the tender offer and,  together  with the Units it
previously  owned,  was the owner of  approximately  40% of the total  number of
Units outstanding for an aggregate of $10.4 million. After purchasing additional
units in 1999 and 2000, the Company owned 1,948,571 units, or approximately  41%
of the units outstanding.

     On December 31, 1998,  the Company  (through its  wholly-owned  subsidiary,
Bluebird)  acquired from Spirit 76 natural gas reserves and associated assets in
producing  fields  located in Oklahoma  and Texas.  The net  purchase  price was
approximately  $25 million after certain  purchase price  adjustments  including
preferential rights exercised by third parties and other customary adjustments.

     On June 10, 1999, the Company and Bluebird  acquired from Vastar Resources,
Inc. oil and gas reserve  interests in 476 wells, a gas processing plant and two
gas gathering systems located in the states of Texas,  Oklahoma and Arkansas for
a  purchase  price  of $32.5  million  after  purchase  price  adjustments.  The
effective date of the transaction was April 1, 1999.

     On December  1, 1999,  Bluebird  acquired a 50%  interest in the Madill Gas
Processing  Plant and  associated  gas  gathering  system from Dynegy Inc. for a
purchase price of $4.1 million after purchase price  adjustments.  The effective
date of the transaction was November 1, 1999.

     The following summary,  prepared on a pro forma basis, presents the results
of  operations  for  the  years  ended  December  31,  1999  and  1998 as if the
acquisitions occurred as of the beginning of the respective years. The pro forma
information  includes  the  effects of  adjustments  for  increased  general and
administrative  expense,  interest expense,  depreciation,  depletion and income
taxes:

                                                   (Unaudited)
                                         ---------------------------------
                                            1999                   1998
                                            ----                   ----
                                    (in thousands, except for per share amounts)
                                    --------------------------------------------

Revenue............................  $         73,104            $      77,181
Net Income (Loss) Applicable
  to Common Stock..................           (12,022)                 (44,911)
Net Income (Loss) Per Common Share
   Basic...........................  $          (0.61)           $       (2.12)
  Diluted..........................  $          (0.61)           $       (2.12)


NOTE 3 -- NOTES RECEIVABLE

     On  September  30,  1997,  the Company sold its  investment  in  securities
available-for-sale to an unrelated entity for $483,500.  Prior to the sale, this
entity owed the  Company  $92,610.  The total  amount owed was secured by a note
payable to the Company with interest at 10% per annum and principal installments
of $50,000  per month  commencing  November  5, 1997,  with  final  payment  due
November 5, 1998.  The note is  collateralized  by shares of an  American  Stock
Exchange  listed company and by shares of the Company held by the entity.  After
making the  payment  due  November  5, 1997,  the entity was unable to  continue
making  further  payments.  The net carrying  value of the note, at December 31,
1997 was $350,016. During 1998, the Company made further advances of $290,525 to
this  entity,  and at December  31, 1998 an  additional  allowance  provision of
$590,525 was made. The carrying value of the note, net of allowance, at December
31, 2000 and 1999 was $50,016.  Subsequent  to December  31,  2000,  the Company
received a payment of $50,000 to apply against this note.

                                      F-11
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

NOTE 4 -- RELATED PARTY TRANSACTIONS

     In conjunction  with the acquisition of Hunter,  the Company assumed a note
receivable  with a balance of $379,321 at  December  31, 1999 and 1998,  from an
owner in an affiliated limited liability company. The note provides for interest
at 10 percent and has a due date of December 31, 2000.  The note was not paid by
the due date,  and the  Company  has  commenced  legal  proceedings  in order to
recover the amount due.  The note is secured by interest in a real estate  joint
venture.

     At December  31, 2000 and 1999,  the  Company's  note  receivable  from the
Magnum  Hunter   Employee  Stock   Ownership  Plan  (ESOP)  was  $2,780,000  and
$1,638,000,  respectively.  The  purpose  of the  loan is to  allow  the ESOP to
purchase Magnum Hunter  Resources  common stock on the open market.  The loan is
interest  free,  due December 31, 2004 and is secured by shares of the Company's
common stock which have not been earned by participants in the ESOP. At December
31, 2000 and 1999,  the number of unearned  shares in the ESOP were  680,282 and
537,515,  respectively.  The unearned shares and their  corresponding costs were
reflected on the  consolidated  balance  sheets of the Company as  reductions to
stockholders' equity.

     During 1998, the Company's Board of Directors authorized the acquisition of
certain shares of a publicly  traded oil and gas company from Mr. Gary C. Evans,
President and Chief Executive  Officer of the Company,  at Mr. Evans' cost basis
in such shares of stock for purposes of a long-term investment.  The shares were
purchased for a total of $442,019.  The Company has the right to cause Mr. Evans
to repurchase the shares back from the Company at the equivalent  price that the
Company  purchased the shares from Mr. Evans.  The value paid for the shares was
in excess of the publicly traded value of the shares on the acquisition  date by
$159,481.  For accounting purposes, the purchase price of the shares was treated
as  a  receivable  from  stockholder  and  has  been  shown  as a  reduction  to
stockholders' equity at December 31, 2000 and 1999.

     During December 1998, the Company's Board of Directors authorized a loan of
up to $300,000 be made available to Mr. Evans, as part of his 1998  compensation
package and to exercise  certain  stock  options.  A total of $230,000 was drawn
under the loan and was  outstanding at December 31, 1998.  During the year ended
December 31, 1999,  the Company  advanced an additional  $188,000 and was repaid
$65,000,  leaving a balance due the  Company,  including  accrued  interest,  of
$371,860 at December 31, 1999,  which was  authorized by the Board of Directors.
The  unpaid  principal  amount  of  these  loans  was  classified  as a loan  to
stockholder  at December 31, 1999 and 1998 and as a reduction  to  stockholders'
equity.  On January 7, 2000,  Mr. Evans repaid  $225,000 on the loan,  leaving a
principal balance of $146,860.  On April 17, 2000 Mr. Evans re-borrowed $100,000
under this loan, and on August 18, 2000, he repaid $258,731,  including  accrued
interest, bringing the balance to zero. On December 28, 2000, Mr. Evans borrowed
$294,938,  which was the balance  owed to the  Company on December  31, 2000 and
included in notes  receivable  from  affiliate.  On January 15, 2001,  Mr. Evans
repaid $295,261, including accrued interest, bringing the balance to zero.

     On November 28, 2000,  Mr.  Matthew C. Lutz,  Chairman and  Executive  Vice
President of the Company, borrowed $65,000 from the Company with the approval of
the Board of Directors. On January 15, 2001, Mr. Lutz repaid the loan, including
accrued interest.

                                      F-12
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

NOTE 5 -- DEBT

     Notes payable and long-term debt at December 31, 2000 and 1999 consisted of
the following:
<TABLE>
<CAPTION>
<S>                                                                         <C>                  <C>
                                                                                 2000              1999
                                                                                     (in thousands)
                                                                            -----------------------------------
Long-Term Debt, with recourse to the Company:

Banks
Revolving   promissory  note,   collateralized  by  pipeline  and
  oil  and  gas properties, due April 30, 2003 (effective rate of 8.52% at
  December 31, 2000) (a)...................................................     $      30,500    $    53,000

Note payable to bank collateralized by vehicle,  payable in monthly
  installments of $1,753 including interest at 7.9% through
  January 2003.............................................................                39              -

Other
Senior notes, unsecured, due June 1, 2007, interest at 10% payable
  semi-annually on June 1 and December 1...................................           140,000        140,000

Notes payable, non-interest bearing and uncollateralized, payable in
  monthly installments of $1,000 through July 1, 2000......................                 -              6
                                                                           ------------------------------------
         Total Long-Term Debt, with recourse...............................     $     170,539    $   193,006
                 Less Current Portion......................................                19              6
         Long-Term Debt, with recourse.....................................     $     170,520    $   193,000
                                                                           ====================================

Long-Term Debt, non recourse to the Company:

Banks
Revolving promissory note, collateralized by pipeline and oil and gas
  properties and 1,840,270 units of TEL Offshore Trust, due June 7, 2002
  (effective rate of 9.48% at December 31, 2000) (b).......................     $      20,600    $     41,800
                                                                           ------------------------------------
         Total Long-Term Debt, non recourse................................     $      20,600    $     41,800
                                                                           ====================================
</TABLE>
                                      F-13
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     Maturities  of long-term  debt based on  contractual  requirements  for the
years ending December 31, are as follows:


                                                                  (in thousands)
2001................................................................. $       19
2002.................................................................     20,619
2003.................................................................     30,501
2004 to 2006.........................................................          -
2007.................................................................    140,000
                                                                     -----------
         Total....................................................... $  191,139
                                                                     ===========

     (a) The  revolving  promissory  note to the  banks is a  borrowing  under a
$125,000,000  line  of  credit  on  which  there  existed  a  borrowing  base of
$53,000,000  at December 31, 2000.  The level of the borrowing base is dependent
on the valuation of the assets  pledged,  primarily oil and gas reserve  values.
The line of credit includes  covenants,  the most  restrictive of which requires
maintenance of a current ratio, interest coverage ratio, and tangible net worth,
as specified in the loan  agreement.  The bank group must approve all  dividends
paid on common stock. The credit  agreement  provides for both "LIBOR" and "Base
Rate" (Prime) interest rate options.  At December 31, 2000, the amounts borrowed
at these rates were:


                                                                  (in thousands)
LIBOR + 1.75% (total of 8.39%)....................................  $     28,000
Base Rate (Prime) + .50% (total of 10.00%)........................         2,500
                                                                  --------------
       Total......................................................  $     30,500
                                                                  ==============

     (b) The  revolving  promissory  note to the  banks is a  borrowing  under a
$75,000,000  line  of  credit  on  which  there  existed  a  borrowing  base  of
$42,000,000  at December 31, 2000.  The level of the borrowing base is dependent
on the valuation of the assets pledged,  primarily oil and gas reserves, natural
gas processing plants, and units of Tel Offshore Trust. On December 1, 2000, the
line of credit  was  amended  to  automatically  increase  from  $38,500,000  to
$42,000,000  until  February 28, 2001, at which time it reduced to  $37,000,000.
The line of credit includes  covenants,  the most  restrictive of which requires
maintenance of a current ratio and an interest  coverage ratio, and restrictions
on upstream  loans,  dividends and  commingling of funds.  The credit  agreement
provides for both "LIBOR" and "Base Rate"  (Prime)  interest  rate  options.  At
December 31, 2000 the amounts borrowed at these rates were:


                                                                  (in thousands)
LIBOR + 2.75% (total of 9.44%)....................................$       20,000
Base Rate (Prime) + 1.25% (total of 10.75%).......................           600
                                                                  --------------
       Total......................................................$       20,600
                                                                  ==============

NOTE 6 -- PRODUCTION PAYMENT LIABILITY

     In  November,   1996,  the  Company  entered  into  a  production   payment
conveyance.  The Company  received a production  payment  amount of $750,000 and
agreed to make royalty payments of up to 50% of the monthly net revenue proceeds
received  from  certain  oil and gas  properties.  The  balance  owed  under the
conveyance   was   $359,000   and  $460,000  at  December  31,  2000  and  1999,
respectively.  The  production  payment bears  interest at the rate of 13.5% per
annum and is non-recourse to the Company.

                                      F-14
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

NOTE 7 -- INCOME TAXES

     The Company  accounts  for income  taxes in  accordance  with SFAS No. 109,
"Accounting for Income Taxes",  which requires the recognition of a liability or
asset,  net of a valuation  allowance,  for the deferred tax consequences of all
temporary  differences  between the tax bases and the reported amounts of assets
and liabilities, and for the future benefit of operating loss carryforwards. The
following is a reconciliation of income tax expense reported in the statement of
operations:
<TABLE>
<CAPTION>
<S>                                                      <C>                <C>                 <C>
                                                               2000              1999              1998
                                                                            (in thousands)
                                                        --------------------------------------------------------
Income tax expense (benefit) at statutory rates.........      $     10,191       $    (2,352)   $     (21,263)
State tax expense (benefit).............................               829              (193)          (1,747)
Change in valuation allowance...........................            (3,875)            2,315            8,370
Other...................................................               410               230                -
                                                        --------------------------------------------------------
       Tax expense (benefit)............................      $      7,555       $         -    $     (14,640)
                                                        ========================================================
</TABLE>

     The tax effects of significant  temporary differences and carryforwards are
as follows:
<TABLE>
<CAPTION>
<S>                                                                     <C>                    <C>
                                                                                   December 31,
                                                                       --------------------------------------
                                                                             2000               1999
                                                                                  (in thousands)
                                                                       --------------------------------------

Property and equipment, including intangible drilling costs...........   $   (18,855)           $   (12,325)
                                                                       --------------------------------------
         Total deferred tax liability.................................   $   (18,855)           $   (12,325)
                                                                       --------------------------------------
Allowance for doubtful accounts.......................................           577                    425
Reserves..............................................................            33                     33
Property and equipment, including intangible drilling costs...........             -                  1,984
Depletion carryforwards...............................................           510                    196
Alternative minimum tax credit........................................           234                      -
Operating loss and other carryforwards................................        30,219                 33,951
                                                                       --------------------------------------
         Total deferred tax assets....................................        31,573                 36,589
                                                                       --------------------------------------
Valuation allowance...................................................        (7,100)               (10,975)
                                                                       --------------------------------------
         Net Deferred Tax Asset (Liability)...........................   $     5,618            $    13,289
                                                                       ======================================
</TABLE>

     The  following  deferred tax benefits  were  excluded  from the benefit for
deferred   income  tax  in  the   Consolidated   Statement  of  Operations   and
Comprehensive  Income at December  31,  1998:  Equity in Earnings of  Affiliate,
$71,000; Minority Interest in Subsidiary Earnings,  $23,000; and Unrealized Loss
on Investments, $801,000.

     The Company and its subsidiaries  have net operating loss  carryforwards of
approximately  $79,504,000 that expire,  if unused,  in years 2001 through 2019.
Current tax laws and  regulations  relating to  specified  changes in  ownership
limit  the  utilization  of the  Company's  net  operating  loss and tax  credit
carryforwards. A change in ownership of greater than 50% of a corporation within
a three year period causes the annual limitations to be placed in effect. Such a
change is deemed  to have  occurred  February  3,  1999 in  connection  with the
purchase of preferred stock by ONEOK Resources Company. Approximately $1,274,000
of the net operating losses are subject to a limitation of $718,000 per year and
$50,139,000 are subject to a limitation of $7,850,000 per year. In addition, the
Company has depletion  carryforwards of $2,056,000 with no expiration  period. A
valuation  allowance  reduces  deferred taxes based on the criteria set forth in
SFAS 109.

                                      F-15
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

NOTE 8 -- STOCKHOLDERS' EQUITY

Preferred Stock

     Shares  of  preferred  stock  may be  issued  in  such  series,  with  such
designations,  preferences, stated values, rights, qualifications or limitations
as determined  solely by the Board of  Directors.  Of the  10,000,000  shares of
$.001 par value  preferred  stock the Company is  authorized  to issue,  216,000
shares have been  designated as Series A Preferred  Stock,  925,000  shares have
been designated as Series B Preferred Stock, 625,000 shares have been designated
as Series C  Preferred  Stock,  1,000,000  shares have been  designated  as 1996
Series A Convertible  Preferred  Stock and 50,000 shares have been designated as
1999 Series A 8% Convertible  Preferred Stock. Thus,  7,184,000 preferred shares
have been  authorized  for issuance but have not been issued nor have the rights
of these  preferred  shares been  designated.  No  dividends  can be paid on the
common stock until the dividend  requirements of the preferred  shares have been
satisfied.

     Holders of the Series A Preferred  Stock are entitled to receive  dividends
only to the extent that funds are available from the West Dilley Prospect.  Such
dividends are limited to $7.50 per share, in the aggregate. Dividend payments to
Series A  preferred  shareholders  are based on fifty  percent  (50%) of the net
operating  revenue  received by the working  interest  owners of the West Dilley
Prospect.  Due to no  production  from the well  located on this  prospect,  the
Company shut this well in and therefore is no longer producing the property. The
Series A dividends are not  cumulative  except for unpaid  amounts due from this
calculation.  No  dividends  have been paid on the Series A preferred  stock and
there is no aggregate  annual  dividend  requirement  for the Series A preferred
stock.

     On December 23, 1996 the Company  issued  1,000,000  shares of new Series A
preferred  stock,  known as the 1996 Series A Convertible  Preferred Stock, in a
private placement, resulting in net proceeds to the Company after offering costs
of $9,280,000.  The shares have a stated and liquidation  value of $10 per share
and pay a fixed annual  cumulative  dividend of eight and three quarters percent
(8.75%) payable quarterly in arrears beginning December 31, 1996. The shares are
convertible  into  shares of  common  stock at a  conversion  price of $5.25 per
share.  Dividends of $438,000,  $875,000 and $875,000 and were declared in 2000,
1999 and 1998,  respectively.  On June 30, 2000 the holders of the 1996 Series A
Convertible  Preferred  stock  agreed  to  exchange  the  convertible  preferred
securities  for 900,000  warrants to purchase  restricted  common  shares of the
Company's  stock at an exercise price of $5.25 per share with an expiration date
of June 3, 2003 and payment of $10,000,000.  The convertible preferred stock was
transferred  to a  wholly-owned  subsidiary  of the  Company  with the intent of
possibly  re-marketing  the  preferred  stock to a third  party in the future if
deemed necessary. As a result of the exchange, the Company reduced its dividends
to preferred stockholders by $144,000 in 2000.

     On February 3, 1999, the Company sold 50,000 shares of its 1999 Series A 8%
Convertible  Preferred  Stock  for  $50  million  in a  private  placement.  The
Preferred Stock has a liquidation  value of $50 million and is convertible  into
the Company's Common Stock at $5.25 per share.  Dividends on the Preferred Stock
are payable in cash at the rate of 8% per annum and are cumulative.  The Company
used the net proceeds from the  transaction,  approximately  $46.3  million,  to
repay senior bank debt.  Dividends of $3,874,000 and $3,634,000 were declared in
2000 and 1999,  respectively.  On December 7, 2000, the Company  redeemed 25,000
shares of the Preferred stock for a cash payment of $30,540,000,  which included
a  redemption  premium of  $5,540,000.  The  redemption  premium was included in
dividends applicable to preferred stock in the Company's  consolidated statement
of operations and comprehensive income in 2000.

     The preferred shareholders are not entitled to vote except on those matters
in which the consent of the holders of preferred stock is specifically  required
by Nevada  law. If the Company  were to  liquidate  prior to payment of the full
dividend  requirements on the preferred stock, the preferred stock would receive
a liquidation  preference from the liquidation proceeds.  The Series A preferred
shareholders  would  receive an amount equal to the lesser of the proceeds  from
the  liquidation of the West Dilley Prospect or the remaining  unpaid  dividend.
The 1996 Series A Convertible Preferred Stock would receive an amount of $10 per
share.  On  liquidation,  holders of all series of the preferred  stock would be
entitled to receive the par value,  $.001 per share, in preference to the common
stock shareholders.

                                      F-16
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

Warrants

     In January 1996, 60,000 warrants were issued at an exercise price of $3.375
per share with an expiration  date of January 1999.  None of these warrants were
exercised in 1999 and they expired  unexercised.  In connection with the receipt
of a production payment, in October 1996 the Company issued 25,000 warrants with
an exercise price of $5.18,  25,000 warrants with an exercise price of $5.65 and
25,000 warrants with an exercise price of $6.13,  all expiring October 2001. All
of these warrants were exercised on October 17, 2000,  resulting in net proceeds
to the Company of $424,000.

     In January 1997,  21,000  warrants were issued at a exercise price of $4.50
per share,  expiring January 1, 2000, in connection with services  rendered by a
non-employee. The warrants were not exercised in 1999 and expired unexercised in
January 2000.

     In July 1999,  the  Company  issued a total of  10,512,150  warrants on the
basis of one warrant for every three common  shares owned,  .63492  warrants for
every  share of 1996  Series A  Convertible  Preferred  Stock  owned and  63.492
warrants  for every s hare of 1999  Series A 8%  Convertible  Stock  owned.  The
warrants had an exercise  price of $6.50 per share,  an expiration  date of June
30, 2002 and were  redeemable  by the Company at any time prior to expiration at
$0.01 per  share.  The  warrants  were  publicly  traded on the  American  Stock
Exchange.  On October  17,  2000,  3,174,600  of the  warrants  were  exercised,
resulting  in net proceeds to the Company of  $20,634,900.  On October 26, 2000,
the Company announced that it would redeem the remaining  7,337,550  warrants if
they were not  exercised  by  December  5, 2000.  As a result of the  redemption
notice,  5,263,536  warrants were exercised,  including 164,946 by the Company's
ESOP,  and a total of 1,429,264  warrants were redeemed by the Company for $0.01
per share,  resulting  in net  proceeds of  $33,206,707  after  redemptions.  On
November 27, 2000,  the Board of Directors  allowed a total of 644,749  warrants
held by certain key officers and directors of the Company to be exchanged for an
equal number of new warrants with an exercise  price of $6.75 per share expiring
on December  31, 2003.  The  exercise  price of the new warrants was fair market
value on the date of the new grant.

     On June 30, 2000,  the holders of the  Company's  1996 Series A Convertible
Preferred  stock agreed to exchange the  convertible  preferred  securities  for
900,000 warrants to purchase  restricted common shares of the Company's stock at
an exercise  price of $5.25 per share with an  expiration  date of June 30, 2003
and payment of $10,000,000.  A provision of the exchange  agreement  allowed the
Company to require  the  exercise of the  warrants  if the closing  price of the
Company's  common stock was above $7.50 per share for fifteen  consecutive  days
subsequent to June 30, 2000. On October 5, 2000 a total of 450,000 warrants were
exercised for cash,  resulting in net proceeds to the Company of $2,362,500.  On
the same date, the remaining  450,000  warrants were exercised  using a cashless
exercise feature, resulting in the issuance of 177,272 shares of common stock.

     At December 31, 2000 the Company had a total of 644,749 warrants issued and
outstanding.

     Warrants issued to non-employees  are valued based on the fair market value
of the equity instrument  issued  determined by using the Black-Scholes  pricing
model,  if a quoted  market price is not  available.  The  measurement  date for
warrants issued in exchange for goods and services is established as the earlier
of the date at which a  performance  commitment  is reached or the date at which
the counterparty's performance is complete.

                                      F-17
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

Common Stock

     On January 9, 1998, the Company  adopted a Shareholder  Rights Plan.  Under
the Rights  Plan,  the Rights  initially  represent  the right to  purchase  one
one-hundredth of a share of 1998 Series A Junior  Participating  Preferred Stock
for $35.00 per one one-hundredth of a share. The Rights become  exercisable only
if a person or a group  acquires or  commences a tender offer for 15% or more of
the Company's common stock. Until they become exercisable,  the Rights attach to
and trade with the Company's common stock. The Rights expire January 20, 2008.

     On September 8, 1998, the Company announced a stock repurchase  program for
up to one million  shares of the  Company's  common  stock in the open market or
privately  negotiated  transactions,  to be completed before April 30, 1999 at a
value not to exceed $4 million in the aggregate.  Through December 31, 1998, the
Company had  repurchased  625,600  shares for $1.9 million  under this  program.
Additionally  in  1998,  12,813  shares  of  the  Company's  common  stock  were
contributed  to the 401(k)  plan,  96,913  shares were  issued upon  exercise of
employee  stock  options,  291,300  shares were purchased by the ESOP and 40,877
shares were released by the ESOP to participants.

     On February 17, 1999, the Company  revised its previously  announced  stock
repurchase program to spend up to $4 million without a share limitation.  During
1999,  the  Company  repurchased  601,472  shares of its  common  stock for $1.7
million.  Additionally in 1999, 41,115 shares of the Company's common stock were
contributed  to the 401(k)  plan,  102,145  shares were issued upon  exercise of
employee  stock  options,  338,900  shares were purchased by the ESOP and 51,808
shares were released by the ESOP to participants.

     In April 2000, the Company announced a stock repurchase program whereby the
Company or its affiliates  were  authorized to repurchase up to an additional 5%
of the Company's  outstanding  common  stock.  In May 2000,  Bluebird  purchased
129,032 shares of the Company's common stock for $500,000.  On December 22, 2000
the Company  acquired a 5.5% net profits  interest in the Panoma  properties and
gas gathering  system for  $3,480,418  through the issuance of 356,966 shares of
common stock.  Additionally in 2000,  shares  totaling  656,392 were issued upon
exercise  of employee  stock  options for net  proceeds  of  $2,413,336,  shares
totaling  9,140,408  were issued upon  exercise of warrants  (including  177,272
shares  issued in a  cashless  exercise  and  164,946  shares  exercised  by the
Company's  ESOP) for net proceeds of $57,556,569,  shares totaling  118,916 were
purchased by the ESOP (other than the 164,946  obtained by exercise of warrants)
for  $519,948,  and  shares  totaling  141,095  were  released  by the  ESOP  to
participants.

NOTE 9 -- SUPPLEMENTAL CASH FLOW INFORMATION

     During  2000,  the  Company  purchased  oil and gas  properties  by issuing
356,966  shares valued at $3,480,418.  In accordance  with SFAS 115, the Company
wrote-up  the  carrying  costs  of  its  marketable  investments  by  $2,006,986
($1,246,840 after income tax expense). Interest paid in 2000 was $21,661,000.

     During 1999,  the Company  contributed  41,115 shares valued at $123,000 to
the Company's  401(k) plan. In accordance  with SFAS 115, the Company wrote down
the carrying costs of its marketable  investments by $617,000.  Interest paid in
1999 was $19,773,000.

     During 1998, the Company contributed 12,813 shares valued at $66,000 to the
Company's  401(k) plan. The Company  acquired  certain oil and gas properties in
exchange for notes and accounts  receivable totaling  $1,903,000.  In accordance
with SFAS 115,  the Company  wrote- down the  carrying  costs of its  marketable
investments by $2,304,000  ($1,429,000 after income tax benefit).  Interest paid
in 1998 was $17,089,187.

NOTE 10 -- ENVIRONMENTAL ISSUES

     Being engaged in the oil and gas exploration and development business,  the
Company  may  become   subject  to  certain   liabilities   as  they  relate  to
environmental  clean  up  of  well  sites  or  other  environmental  restoration
procedures as they relate to the drilling of oil and gas wells and the operation
thereof.  In the Company's  acquisition  of existing or previously  drilled well
bores, the Company may not be aware of what environmental  safeguards were taken
at the time such  wells  were  drilled  or during  the time that such wells were
operated.  Should it be determined  that a liability  exists with respect to any
environmental  clean-up or  restoration,  the liability to cure such a violation
would most likely fall upon the Company.  In certain  acquisitions,  the Company
has received  contractual  warranties  that no such violations  exist,  while in
other  acquisitions the Company has waived its rights to pursue a claim for such
violations from the selling party. No claim has been

                                      F-18
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     made  nor  has a claim  been  asserted,  nor is the  Company  aware  of the
existence of any material liability which the Company may have, as it relates to
any  environmental  clean-up,  restoration  or the  violation  of any  rules  or
regulations relating thereto.

NOTE 11 -- COMMITMENTS AND CONTINGENCIES

     The Company has certain  lease  agreements  for the use of office space and
office  equipment.  The office space lease extends through November 2005 with an
option to renew the lease for a three year term.  The various  office  equipment
leases extend until 2003. The leases have been  classified as operating  leases.
The following is a schedule by years of future minimum lease  payments  required
under the operating lease agreements:


Year Ended December 31:
2001...........................................................      $  719,822
2002...........................................................         718,346
2003...........................................................         638,884
2004...........................................................         630,716
2005...........................................................         557,366
Thereafter.....................................................               -
                                                                ----------------
 Total Minimum Payments Required...............................      $3,265,134

     Rental  expense was $717,636,  $367,000 and $327,934,  for 2000,  1999, and
1998, respectively.

     In December,  1997,  the Company  amended its Revolving Loan Agreement with
certain  banks  to  permit  guarantees  of  NGTS,  LLC's  debt,  not  to  exceed
$4,000,000,  and trade payables or letters of credit for the purchase of natural
gas not to exceed an  aggregate  of  $15,000,000  on behalf of NGTS,  LLC. As of
December 31, 2000 and 1999,  there was no NGTS,  LLC debt  outstanding  that the
Company guaranteed.

NOTE 12 -- FINANCIAL INSTRUMENTS AND CONCENTRATION OF CREDIT RISK

     Financial  instruments  that  subject the  Company to credit  risk  consist
principally of accounts and notes receivable. The receivables are primarily from
companies in the oil and gas business or from  individual oil and gas investors.
These parties are primarily  located in the  Southwestern  regions of the United
States.  No single  receivable is considered to be  sufficiently  material as to
constitute a concentration.  The Company does not ordinarily require collateral,
but in the case of receivables for joint  operations,  the Company often has the
ability to offset amounts due against the participant's share of production from
the related  property.  The Company believes the allowance for doubtful accounts
at December 31, 2000 is adequate.

     To the extent the Company  receives the spread  between the contract  floor
and the Index  price  applied to related  contract  volumes,  the  Company has a
credit risk in the event of nonperformance of the counterparty to the agreement.
The Company does not anticipate any material impact to its results of operations
as a result of nonperformance by such parties.

     Management  estimates  the market  values of notes  receivable  and payable
based on expected  cash flows.  At December  31, 2000 and 1999,  the Company had
provided a reserve for the carrying value of a note receivable of $1,170,000 and
$790,000,  respectively.  After establishing this reserve,  management  believes
those market values  approximate  carrying values at December 31, 2000 and 1999.
The market values of equity  investments  are based upon quoted prices (see Note
1). At December 31, 2000,  the fair value of the Company's debt was equal to its
carrying  value,  except  for the 10%  Senior  Notes.  The fair value of the 10%
Senior Notes was $138,600,000.

                                      F-19
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

NOTE 13 -- COMMODITY DERIVATIVES AND HEDGING ACTIVITIES

Crude Oil and Natural Gas Hedges

     Periodically,  the Company enters into futures, options, and swap contracts
to mitigate the effects of significant fluctuations in crude oil and gas prices.
At December 31, 2000, the Company had the following open contracts:
<TABLE>
<CAPTION>
<S>      <C>                  <C>                       <C>                      <C>
               Type               Volume/Month                Duration                Avg. Price
          ---------------     ---------------------     ---------------------    ---------------------
Oil
------
          Collar.........           30,000 Bbl            Jan 01 - Jun 01           Floor - $25.00
                                                                                    Cap   - $33.50
          Collar.........           15,000 Bbl            Jan 01 - Jun 01           Floor - $25.00
                                                                                    Cap   - $34.35
          Collar.........           15,000 Bbl            Jan 01 - Jun 01           Floor - $25.00
                                                                                    Cap   - $35.50
          Collar.........           15,000 Bbl            Jan 01 - Jun 01           Floor - $25.00
                                                                                    Cap   - $36.80
Gas
------
          Collar.........          300,000 MMBtu          Jan 01 - Dec 01           Floor - $ 4.50
                                                                                    Cap   - $ 6.15
</TABLE>

     Based on future market prices at December 31, 2000,  the fair value of open
contracts to the Company was a liability of $2.8 million.

     Net  gains  (losses)  related  to  crude  oil and  natural  gas  derivative
transactions  for the  years  ended  December  31,  2000,  1999  and  1998  were
$(11,179,000), $(3,232,000) and $2,739,000, respectively.

Interest Rate Swaps

     On June 30, 1999, the Company entered into two interest rate swaps in order
to shift a  portion  of the  fixed  rate bond debt to  floating  rate  debt,  to
capitalize on what was perceived as a market  overreaction  to pending  interest
rate  increases by the Federal  Reserve and to  effectively  lower interest rate
expense over the next twelve  months.  On June 1, 2000, one of the interest rate
swaps terminated. The following table reflects the terms of the remaining swap.
<TABLE>
<CAPTION>
<S>                           <C>                   <C>                    <C>                 <C>
            Type                 Notional Amount      Termination Date         Pay Rate            Receive Rate
-----------------------------  -------------------   ------------------   ------------------   --------------------
 Pay Variable/Receive Fixed        $50,000,000            06/01/02          LIBOR + 3.34%           10% fixed
                                                                           through 05/31/00

                                                                            LIBOR + 3.69%
                                                                           from 06/01/00 to
                                                                               06/01/02
</TABLE>

     The Company's total fixed rate debt at December 31, 2002 was  approximately
$140 million.

     Based on future  market rates at December 31, 2000,  the fair value of open
contracts to the Company was an asset of $179,000.

     Net gains (losses) related to interest rate derivative transactions for the
years ended December 31, 2000, 1999 and 1998 were $(13,000),  $209,000 and none,
respectively.

                                      F-20
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

NOTE 14 -- STOCK COMPENSATION PLANS

     The Company adopted in 1996 two stock  compensation plans for its employees
and directors,  (i) the Magnum Hunter  Resources  Employee Stock Ownership Plan,
(the "ESOP"),  and (ii) the Magnum Hunter  Resources,  Inc. 1996 Incentive Stock
Option Plan (the "Option Plan"). In addition, the Company has made non-incentive
stock option grants in 2000, 1999 and 1998.

ESOP

     The Company  established an ESOP and a related trust in 1996 as a long-term
benefit for its employees.  Under terms of the ESOP,  eligible  participants may
elect to make elective  deferred  contributions of not less than 1% or more than
15% of their annual compensation, limited in combination with the 401(k) plan to
the  maximum   allowable  per  year  by  the  Internal  Revenue  Code.   Company
contributions  to the  ESOP are made on a  discretionary  basis.  It is also the
Company's intent to invest all  contributions in the Company's Common Stock. All
employees  who have  reached  the age of 21 and with  one  year of  service  are
eligible to  participate  in the plan.  Shares  purchased by the ESOP with loans
from the Company are released to participants as Company  contributions are made
and the related loans are repaid. The Company has no repurchase obligations with
respect to released shares.

     During  1998,  the Company  loaned the ESOP  $878,997  to purchase  291,300
shares of the  Company's  Common Stock on the open market at an average price of
$3.02 per share. At December 31, 1998, the Company  contributed  $123,345 to the
ESOP as a discretionary  contribution  under the plan. The ESOP then repaid that
portion  of its  outstanding  loan  from the  Company  and  40,877  shares  were
allocated among the plan participants.

     During 1999,  the Company  loaned the ESOP  $1,030,365 to purchase  338,900
shares of the  Company's  Common Stock on the open market at an average price of
$3.04 per share. At December 31, 1999, the Company  contributed  $150,782 to the
ESOP as a discretionary  contribution  under the plan. The ESOP then repaid that
portion  of its  outstanding  loan  from the  Company  and  51,808  shares  were
allocated among the plan participants.

     During 2000,  the Company  loaned the ESOP  $1,592,098 to purchase  118,916
shares of the  Company's  common stock on the open market at an average price of
$4.37 per share and to exercise  164,946 warrants at a price of $6.50 per share.
On  December  8,  2000,  the  Company  contributed  $448,454  to the  ESOP  as a
discretionary  contribution under the plan. The ESOP then repaid that portion of
its  outstanding  loan from the Company and 141,095 shares were allocated  among
the plan  participants.  The loan is interest free and is due December 31, 2004.
The loan was  secured by  680,282  shares and  537,515  shares of the  Company's
common stock at December 31, 2000 and 1999, respectively.

     As required  under  Statement of Position 93-6  "Employers'  Accounting for
Employee Stock  Ownership  Plans,"  compensation  expense is recorded for shares
committed  to be released to  employees  based on the fair market value of those
shares when they are committed to be released.  The difference  between cost and
the fair market  value of the  committed  to be  released  shares is recorded in
additional  paid-in-  capital.  Unreleased  shares held by the ESOP are excluded
from the calculation of earnings per share.

     The ESOP shares are summarized as follows:


                                                 December 31,
                                         2000                     1999
                              -------------------------- -----------------------
Allocated shares                         256,336                 115,241
Unreleased shares                        680,282                 537,515
                                         -------                 -------
  Total ESOP shares                      936,618                 652,756
                                         =======                 =======
Fair value of unreleased shares      $ 8,163,384             $ 1,545,356

     The ESOP expense for the years ending  December 31, 2000, 1999 and 1998 was
$1,119,942, $148,948 and $122,631, respectively.

                                      F-21
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

Stock Option Plans

  Incentive Stock Option Plan

     The Company  established  this plan beginning April 1, 1996. It is governed
by Section 422 of the Internal Revenue Code, and Section 16(b) of the Securities
Exchange Act of 1934. This Option Plan covers  1,200,000 shares of the Company's
Common Stock.  Eligibility  is limited to employees and directors of the Company
and its  subsidiaries.  The actual selection of grantees is made by the Board of
Directors.  The term of the individual option grants, while at the discretion of
the Board, has  historically  been for a term of 5 years. All options granted in
1996 were fully vested and exercisable when granted. The exercise price was fair
market value at the date of grant.

  Non-Incentive Stock Option Grants

     During  1997,  the  Board  granted   1,440,000  options  to  employees  and
directors,  1,240,000  of which were fully vested and 200,000 of which vest over
five years.  The term of the individual  option grants were for five years.  The
exercise price was fair market value on the date of grant.

     During  1998,  the Board  granted  220,000 new options to  employees  at an
average  price of $5.89.  All options were fully vested on the date of grant and
were for a term of five years. On December 14, 1998 the Board repriced 1,590,000
options to employees and  directors  from an average of $5.96 per share to $3.75
per share, the fair market value on that date.

     During 1999,  the Board  granted  1,306,650  new options to employees at an
average price of $2.69, of which 108,000 vested immediately and 1,198,650 vested
20% at the date of grant, with the balance vesting an additional 20% per year on
the anniversary date over the next four years. Additionally, the expiration date
of 300,000  options  previously  granted to two former  officers was modified to
extend the expiration date from January 5, 2000 to January 5, 2002.

     During  2000,  the Board  granted  1,536,000  new options to employees at a
weighted  average price of $7.89,  all of which vested 20% at the date of grant,
with the balance vesting an additional 20% per year on the anniversary date over
the next four years, and with a weighted average term of 9.9 years. The exercise
price was the fair market value on the date of grant.

     The following is a summary of stock option activity under the Option Plans:
<TABLE>
<CAPTION>
<S>                                  <C>            <C>           <C>         <C>        <C>            <C>
                                              2000                       1999                      1998
                                   ----------------------------------------------------------------------------------
                                                      Weighted                  Weighted                 Weighted
                                                       Average                   Average                  Average
                                        Shares      Exercise Price  Shares    Exercise Price  Shares   Exercise Price
                                   ----------------------------------------------------------------------------------
Outstanding - Beginning of Year....    3,866,092    $     3.57    2,661,587   $     3.90    2,538,500    $     5.00
Granted............................    1,536,000          7.89    1,306,650         2.69      220,000          5.89
Exercised..........................    (656,392)          3.67    (102,145)          .73     (96,913)           .81
Canceled...........................     (43,300)          3.32            -            -            -             -
Repriced - previous................            -             -            -            -  (1,590,000)          5.96
Repriced - new.....................            -             -            -            -    1,590,000          3.75
                                   ---------------------------------------------------------------------------------
Outstanding - End of Year..........    4,702,400    $     4.97    3,866,092   $     3.57    2,661,587    $     3.90
                                       =========    ==========    =========   ==========    =========    ==========
Exercisable - End of Year..........    2,730,460    $     4.31    2,787,172   $     3.94    2,501,587    $     3.91
                                       =========    ==========    =========   ==========    =========    ==========
</TABLE>

                                      F-22
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     The  following is a summary of stock  options  outstanding  at December 31,
2000:
<TABLE>
<CAPTION>
<S>                                   <C>                    <C>                      <C>
                                                                  Weighted
                                                                   Average
                                           Number of              Remaining
                                            Options           Contractual Life             Number of
Exercise Price                            Outstanding              (Years)            Exercisable Options
                                      -----------------------------------------------------------------------

$      2.50..........................            1,143,800           4.0                             440,660
       2.875.........................                3,000           3.0                               3,000
       3.4375........................                8,000           4.2                                   -
       3.75..........................            1,040,600           2.0                           1,000,600
       4.375.........................               23,000           1.0                              23,000
       4.50..........................              843,000           1.0                             843,000
       5.25..........................              110,000           3.1                             110,000
       5.375.........................                5,000           1.3                               5,000
       6.625.........................               21,000           4.6                               4,200
       7.9375........................            1,505,000           9.9                             301,000
                                      -----------------------------------------------------------------------
                                                 4,702,400           4.9                           2,730,460
                                      =======================================================================
</TABLE>

     The Company  adopted  the  disclosures  only  portion of SFAS No. 123 as it
continues to follow the  provisions of APB No. 25, which is the intrinsic  value
method of accounting for stock-based compensation.

     On a pro forma basis, the effect of stock based  compensation  (options and
warrants) had the Company adopted Statement No. 123 is as follows:
<TABLE>
<CAPTION>
<S>                                                         <C>                  <C>                <C>
                                                                            Year Ended December 31,
                                                                    2000               1999              1998
                                                             ---------------------------------------------------------
Net Income (Loss) Applicable to Common Stock:
  As reported..............................................        $ 12,552,000      $(11,335,000)    $(47,955,000)
  Pro Forma................................................           6,800,000       (13,313,000)     (49,160,000)
Basic Earnings (Loss) per Share:
  As reported, after extraordinary loss....................        $       0.60      $      (0.57)    $      (2.27)
  Pro Forma................................................                0.33             (0.67)           (2.32)
Diluted Earnings (Loss) per Share:
  As reported, after extraordinary loss....................        $       0.51      $      (0.57)    $      (2.27)
  Pro Forma................................................                0.30             (0.67)           (2.32)
Weighted average grant date fair value.....................        $  9,259,000      $  1,978,000     $  1,205,000
</TABLE>

     The Company estimated the fair value of each stock based grant (options and
warrants)  using  the  Black-Scholes  option  pricing  method  while  using  the
following weighted average assumptions:

                                     2000            1999             1998
                      ----------------------------------------------------------

Risk-free interest rate.........     5.75%           5.875%           5.5%
Expected life...................     7.4 years       4.4 years        4.1 years
Expected volatility.............     56.0%           53.0%            57.0%
Dividend yield..................      -               -                -

                                      F-23
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

NOTE 15 -- EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND
             CHANGE-IN-CONTROL ARRANGEMENTS

     Mr. Gary C. Evans,  Mr. Matthew C. Lutz, Mr. Richard R. Frazier,  Mr. Chris
Tong,  Mr. R.  Douglas  Cronk and Mr.  Charles  R.  Erwin  each have  employment
agreements with the Company. Mr. Evans' agreement terminates January 1, 2005 and
continues  thereafter  on a year to year  basis  and  provides  for a salary  of
$300,000 per annum unless increased by the Board. Mr. Evans' salary for the year
2001 is $350,000.  Mr. Lutz's agreement terminates January 1, 2005 and continues
thereafter  on a year to year basis and  provides  for a salary of $175,000  per
annum unless  increased  by the Board.  Mr.  Lutz's  salary for the year 2001 is
$245,000.  Mr.  Frazier's  agreement  terminates  January 1, 2005 and  continues
thereafter  on a year to year basis and  provides  for a salary of $175,000  per
annum unless  increased by the Board.  Mr. Frazier's salary for the year 2001 is
$190,000.  Mr.  Tong's  agreement  terminates  January  1,  2003  and  continues
thereafter  on a year to year basis and  provides  for a salary of $160,000  per
annum unless  increased  by the Board.  Mr.  Tong's  salary for the year 2001 is
$165,000.  Mr.  Cronk's  agreement  terminates  January  1,  2003 and  continues
thereafter  on a year to year basis and  provides  for a salary of $122,500  per
annum unless  increased by the Board.  Mr.  Cronk's  salary for the year 2001 is
$138,000.  Mr.  Erwin's  agreement  terminates  January  1,  2003 and  continues
thereafter  on a year to year basis and  provides  for a salary of $125,000  per
annum unless  increased by the Board.  Mr.  Erwin's  salary for the year 2001 is
$145,000. All of the agreements provide that the same benefits supplied to other
Company employees shall be available to the employee.  The employment agreements
also contain, among other things, covenants by the employee that in the event of
termination,  he will not compete with the Company in certain geographical areas
or hire any  employees of the Company for a period of two years after  cessation
of employment.

     In  addition,  all  of the  agreements  contain  a  provision  that  upon a
change-in-control  of the Company and the  employee's  position is terminated or
the  employee  leaves for "good  cause",  the  employee  is entitled to receive,
immediately in one lump sum, certain compensation. In the case of Mr. Evans, Mr.
Lutz and Mr. Frazier, the employee shall receive three times the employee's base
salary,  bonus for the last fiscal year and any other  compensation  received by
him in the last fiscal year. In the case of Mr. Tong and Mr. Cronk, the employee
shall receive the employee's base salary, bonus for the last fiscal year and any
other  compensation  received by him in the last fiscal year  multiplied by two.
Also, any medical, dental and group life insurance covering the employee and his
dependents  shall  continue  until  the  earlier  of (i)  12  months  after  the
change-in-control  or (ii) the date the employee  becomes a  participant  in the
group insurance benefit program of a new employer.  The Company also has key man
life insurance on Mr. Evans in the amount of $12,000,000.

NOTE 16 - SEGMENT DATA

     The Company has three reportable  segments.  The Exploration and Production
segment is engaged in exploratory drilling and acquisition, production, and sale
of crude oil,  condensate,  and natural gas. The Gas  Gathering,  Marketing  and
Processing  segment is engaged in the gathering and  compression  of natural gas
from the wellhead,  the purchase and resale of natural gas which it gathers, and
the processing of natural gas liquids. The Oil Field Services segment is engaged
in the managing and operation of producing oil and gas  properties  for interest
owners.

     The Company's  reportable  segments are strategic business units that offer
different  products  and  services.  They are managed  separately  because  each
business requires different technology and marketing strategies. The Exploration
and Production  segment has six geographic  areas that are  aggregated.  The Gas
Gathering,  Marketing and Processing  segment includes the activities of the two
gathering  systems  and  three  natural  gas  liquids  processing  plants in two
geographic  areas that are  aggregated.  The Oil Field Services  segment has six
geographic  areas that are aggregated.  The reason for aggregating the segments,
in  each  case,  was  due to the  similarity  in  nature  of the  products,  the
production processes, the type of customers, the method of distribution, and the
regulatory environments.

     The accounting  policies of the segments are the same as those described in
Note 1 - Summary of  Significant  Accounting  Policies.  The  Company  evaluates
performance  based on profit or loss from  operations  before income taxes.  The
accounting  for  intersegment  sales  and  transfers  is done as if the sales or
transfers were to third parties, that is, at current market prices.

                                      F-24
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

     Segment data for the three years ended December 31, 2000, 1999 and 1998 are
as follows (in thousands):
<TABLE>
<CAPTION>
<S>                                      <C>            <C>              <C>         <C>        <C>           <C>
                                                        Gas Gathering,
                                         Exploration &    Marketing &    Oil Field
                  2000:                    Production     Processing      Services    All Other  Elimination  Consolidated
                                         ----------------------------------------------------------------------------------
Revenue from external customers.........   $   106,052    $    20,010      $ 1,448      $     -    $      -    $   127,510
Intersegment revenues....................            -         20,218        6,128                  (26,346)             -
Depreciation, depletion, amortization and
impairment...............................       24,350            876          304           26                     25,556

Segment profit (loss)..................         52,743          3,422       (1,274)      (4,562)                    50,329
Equity earnings (losses) of affiliates...                                                 1,307                      1,307
Interest expense.........................                                               (22,298)                   (22,298)
                                                                                                                       477
Other income.............................                                                   477               --------------
Income before income taxes...............                                                                      $    29,815
Current income tax provision.............                                                  (234)                      (234)
Deferred income tax provision............                                                (7,321)                    (7,321)
                                                                                                              --------------
Net income...............................                                                                      $    22,260
                                                                                                              ==============
Capital expenditures (net of asset sales)  $    20,279    $       119      $   495      $     -                $    20,893
</TABLE>

<TABLE>
<CAPTION>
<S>                                      <C>           <C>              <C>         <C>         <C>           <C>
                                                         Gas Gathering,
                                          Exploration &   Marketing &    Oil Field
                  1999:                    Production      Processing     Services    All Other  Elimination  Consolidated
                  -----                 ----------------------------------------------------------------------------------
Revenue from external customers.........    $    60,673      $    8,185    $   768     $     -    $      -    $    69,626
Intersegment revenues....................             -          14,135      6,164           -     (20,299)             -
Depreciation, depletion, amortization and
impairment...............................        21,176             646        233          17                     22,072

Segment profit (loss)..................          15,960           1,858       (605)     (2,101)                    15,112
Equity earnings (losses) of affiliates...                                                 (103)                      (103)
Interest expense.........................                                              (22,103)                   (22,103)
Other income.............................                                                  354                        354
                                                                                                             -------------
Loss before income taxes.................                                                    -                $    (6,740)
Deferred income tax benefit..............                                                    -                          -
Minority interest........................                                                  (86)                       (86)
                                                                                                             -------------
Net loss.................................                                                                     $    (6,826)
                                                                                                             =============

Capital expenditures (net of asset sales)   $    54,877      $    3 ,331   $   410     $     -                $    58,618
</TABLE>

                                      F-25
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)
<TABLE>
<CAPTION>
<S>                                     <C>            <C>               <C>         <C>        <C>           <C>
                                                        Gas Gathering,
                                         Exploration &    Marketing &    Oil Field
                  1998:                    Production     Processing      Services    All Other  Elimination  Consolidated
                  -----                  ----------------------------------------------------------------------------------
Revenue from external customers.........   $   43,565   $      6,954      $  881      $     -      $       -    $  51,400
Intersegment revenues....................           -         12,569       4,561            -        (17,130)           -
Depreciation, depletion, amortization and
impairment...............................      63,681            652         148           21                      64,502
Segment profit (loss)..................       (42,953)           521       1,465       (2,047)                    (43,014)
Equity earnings (losses) of affiliates...                                                (116)                       (116)
Interest expense.........................                                             (18,207)                    (18,207)
Other income.............................                                                 624                         624
                                                                                                               -------------
Loss before income taxes.................                                                                       $ (60,713)
Deferred income tax benefit..............                                              13,670                      13,670
Minority interest........................                                                 (37)                        (37)
                                                                                                               -------------
Net loss.................................                                                                       $ (47,080)
                                                                                                               =============

Capital expenditures (net of asset sales)  $   70,294   $        (35)     $  740      $    38                   $  71,037
</TABLE>

<TABLE>
<CAPTION>
<S>                                       <C>            <C>              <C>         <C>        <C>         <C>
                                                         Gas Gathering,
                                           Exploration &    Marketing &    Oil Field
                                            Production     Processing      Services    All Other  Elimination Consolidated
                                          ---------------------------------------------------------------------------------
As of December 31, 2000
Segment assets............................ $     270,195  $     20,561     $  16,154    $  8,702               $    315,612
Equity subsidiary investments.............                                                 8,054

As of December 31, 1999
Segment assets............................ $     278,652  $     12,416     $   4,252    $  8,702               $    304,022
Equity subsidiary investments.............                                                 4,163                      4,163
</TABLE>


NOTE 17 -- CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

     The   Company   and  its   subsidiaries,   except   Bluebird   and  certain
inconsequential  subsidiaries (Inesco Corporation,  SPL Gas Marketing,  Inc. and
Midland Hunter Petroleum Limited Liability Company) are direct Guarantors of the
Company's  10% Senior Notes and have fully and  unconditionally  guaranteed  the
Notes on a joint and several  basis.  Bluebird  was formed in December  1998 and
first reported  results of operations in fiscal 1999. In addition to not being a
guarantor  of  the  Company's  10%  Senior  Notes,  it  cannot  be  included  in
determining  compliance  with certain  financial  covenants  under the Company's
credit agreements.  Management has determined that separate financial statements
relating  to  the   Guarantors   are  not  material  to   investors.   Condensed
consolidating  financial  information  for Magnum  Hunter  Resources,  Inc.  and
subsidiaries  as of December 31, 2000 and 1999 and for the years ended  December
31, 2000 and 1999 is as follows:

                                      F-26
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)


                 Magnum Hunter Resources, Inc. and Subsidiaries
                     Condensed Consolidating Balance Sheets
<TABLE>
<CAPTION>
<S>                                         <C>                     <C>               <C>            <C>
                                December 31, 2000
-------------------------------------------------------------------------------------------------------------------
                                                Magnum Hunter          Bluebird                        Magnum Hunter
                                               Resources, Inc.       Energy, Inc.                     Resources, Inc.
Amounts in Thousands                          And Guarantor Subs    (Non Guarantor)    Eliminations     Consolidated
--------------------
ASSETS
Current assets..............................  $        33,556        $     6,894        $  (5,612)       $   34,838
Property and equipment
  (using full cost accounting)..............          208,115             52,417                -           260,532
Investment in subsidiaries
 (equity method)............................           25,574                  -          (25,574)                -
Other assets................................           27,173                319           (7,250)           20,242
                                            -------------------------------------------------------------------------
   Total Assets.............................  $       294,418        $    59,630        $ (38,436)       $  315,612
                                            =========================================================================

LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities.........................  $        30,123        $     6,206        $  (5,612)       $   30,717
Long-term liabilities.......................          170,879             27,850           (7,250)          191,479
Shareholders' equity........................           93,416             25,574          (25,574)           93,416
                                            --------------------------------------------------------------------------
   Total Liabilities and Stockholders' Equity $       294,418        $    59,630        $ (38,436)       $  315,612
                                            ==========================================================================
</TABLE>

<TABLE>
<CAPTION>
<S>                                         <C>                     <C>               <C>            <C>
                                December 31, 1999
-------------------------------------------------------------------------------------------------------------------
                                                Magnum Hunter          Bluebird                        Magnum Hunter
                                               Resources, Inc.       Energy, Inc.                     Resources, Inc.
Amounts in Thousands                          And Guarantor Subs    (Non Guarantor)    Eliminations     Consolidated
--------------------
ASSETS
Current assets..............................  $        14,572        $     3,741        $  (2,601)       $   15,712
Property and equipment
  (using full cost accounting)..............          211,159             54,036                -           265,195
Investment in subsidiaries
 (equity method)............................           13,302                  -          (13,302)                -
Other assets................................           22,605                510                -            23,115
                                            -------------------------------------------------------------------------
   Total Assets.............................  $       261,638        $    58,287        $ (15,903)       $  304,022
                                            =========================================================================

LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities.........................  $        16,442        $     3,185        $  (2,601)       $   17,026
Long-term liabilities.......................          193,644             41,800                            235,444
Shareholders' equity........................           51,552             13,302          (13,302)           51,552
                                            --------------------------------------------------------------------------
   Total Liabilities and Stockholders' Equity $       261,638        $    58,287        $ (15,903)       $  304,022
                                            ==========================================================================
</TABLE>


                                      F-27
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)

                 Magnum Hunter Resources, Inc. and Subsidiaries
                Condensed Consolidating Statement of Operations
<TABLE>
<CAPTION>
<S>                                        <C>                    <C>                <C>           <C>
                          Year Ended December 31, 2000
-----------------------------------------------------------------------------------------------------------------------
                                                Magnum Hunter          Bluebird                        Magnum Hunter
                                               Resources, Inc.       Energy, Inc.                     Resources, Inc.
Amounts in Thousands                         And Guarantor Subs     (Non Guarantor)   Eliminations     Consolidated
--------------------
                                           ----------------------------------------------------------------------------
Revenues...................................  $         83,048           $ 44,772     $     (310)     $     127,510
Expenses...................................            72,375             25,250             70             97,695
                                           ----------------------------------------------------------------------------
Income (loss) before                                   10,673             19,522           (380)            29,815
 Equity in net earnings of subsidiaries....            12,272                  -        (12,272)                 -
                                           ----------------------------------------------------------------------------
Income (loss) before income taxes..........            22,945             19,522        (12,652)            29,815
Income tax provision.......................              (305)            (7,250)             -             (7,555)
                                           ----------------------------------------------------------------------------
  Net Income (Loss)........................  $         22,640           $ 12,272     $  (12,652)     $      22,260
                                           ============================================================================
</TABLE>

<TABLE>
<CAPTION>
<S>                                      <C>                      <C>              <C>              <C>
                          Year Ended December 31, 1999
-----------------------------------------------------------------------------------------------------------------------
                                                Magnum Hunter          Bluebird                        Magnum Hunter
                                               Resources, Inc.       Energy, Inc.                     Resources, Inc.
Amounts in Thousands                         And Guarantor Subs     (Non Guarantor)   Eliminations     Consolidated
--------------------                        ----------------------------------------------------------------------------
Revenues...................................  $       53,189             $  16,847    $     (410)       $     69,626
Expenses...................................          62,184                14,678          (410)             76,452
                                           ----------------------------------------------------------------------------
Income (loss) before                                 (8,995)                2,169             -              (6,826)
 Equity in net earnings of subsidiaries....           2,169                     -        (2,169)                  -
                                           ----------------------------------------------------------------------------
Income (loss) before income taxes..........          (6,826)                2,169        (2,169)             (6,826)
Income tax provision.......................               -                     -             -                   -
                                           ----------------------------------------------------------------------------
  Net Income (Loss)........................ $        (6,826)            $   2,169    $   (2,169)       $     (6,826)
                                           ============================================================================
</TABLE>

                                      F-28
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (continued)


                 Magnum Hunter Resources, Inc. and Subsidiaries
                Condensed Consolidating Statement of Cash Flows

                          Year Ended December 31, 2000
<TABLE>
<CAPTION>
<S>                                        <C>                   <C>              <C>            <C>

                                                Magnum Hunter         Bluebird                     Magnum Hunter
                                               Resources, Inc.      Energy, Inc.                  Resources, Inc.
Amounts in Thousands                         And Guarantor Subs   (Non Guarantor)  Eliminations    Consolidated
-------------------------------------------------------------------------------------------------------------------
Cash flow from operating activities.........$        21,909         $  27,557      $      -             $  49,466
Cash flow used by investing activities......        (13,501)           (6,507)            -               (20,008)
Cash flow used by financing activities......         (9,964)          (21,375)          325               (31,014)
                                            -----------------------------------------------------------------------
Net increase (decrease) in cash.............         (1,556)             (325)          325                (1,556)
Cash at beginning of period.................          1,565             2,145        (2,145)                1,565
                                            -----------------------------------------------------------------------
Cash at end of period.......................$             9         $   1,820      $ (1,820)            $       9
                                            =======================================================================
</TABLE>

<TABLE>
<CAPTION>
<S>                                        <C>                  <C>               <C>             <C>
                          Year Ended December 31, 1999

                                                Magnum Hunter         Bluebird                     Magnum Hunter
                                               Resources, Inc.      Energy, Inc.                  Resources, Inc.
Amounts in Thousands                         And Guarantor Subs   (Non Guarantor)  Eliminations    Consolidated
-------------------------------------------------------------------------------------------------------------------
Cash flow from operating activities.........   $       6,202       $    11,233      $      -         $  17,435
Cash flow used by investing activities......         (34,668)          (25,209)        1,408           (58,469)
Cash flow provided by financing activities..          25,178            15,662        (3,094)           37,746
                                            -----------------------------------------------------------------------
Net increase (decrease) in cash.............          (3,288)            1,686        (1,686)           (3,288)
Cash at beginning of period.................           4,853               459          (459)            4,853
                                            -----------------------------------------------------------------------
Cash at end of period.......................   $       1,565       $     2,145      $ (2,145)        $   1,565
                                            =======================================================================
</TABLE>

NOTE 18 - SUBSEQUENT EVENT

     Effective  January 1, 2001 the holder of the remaining 25,000 shares of the
Company's 1999 Series A 8% Convertible  preferred  stock  converted those shares
into 4,761,904 shares of the Company's common stock.

                                      F-29
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
   SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - (continued)
                                   (Unaudited)

     Proved oil and gas reserves consist of those estimated  quantities of crude
oil,  gas,  and  natural  gas  liquids  that  geological  and  engineering  data
demonstrate  with  reasonable  certainty to be  recoverable in future years from
known  reservoirs  under  existing  economic and  operating  conditions.  Proved
developed oil and gas reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.

     Estimates of petroleum reserves have been made by independent engineers and
Company  employees.  These estimates include reserves in which the Company holds
an economic  interest  under  production-sharing  and other  types of  operating
agreements.  These estimates do not include probable or possible  reserves.  The
estimated net interests in Proved Reserves are based upon subjective engineering
judgments and may be affected by the  limitations  inherent in such  estimation.
The  process  of  estimating  reserves  is  subject  to  continual  revision  as
additional  information  becomes  available  as a result of  drilling,  testing,
reservoir  studies and production  history.  There can be no assurance that such
estimates will not be materially revised in subsequent periods. The revisions of
previous  estimates of the Company's  proved oil reserves were  primarily due to
changes in commodity  prices at December 31, 1998,  1999 and 2000 that  impacted
whether such reserves were economically recoverable. The impact of price changes
disproportionately  affects the Company's long life reserves because of the more
gradual decline curve of the applicable production.

     Estimated  quantities of proved oil and gas reserves of the Company were as
follows:

                                                                 Gas
                                               Oil            (Thousand
                                            (Barrels)        Cubic Feet)
                                        ------------------------------------

December 31, 1998
  Proved Reserves..................        17,349,000       219,060,000
  Proved developed reserves........         9,475,000       174,987,000
December 31, 1999
  Proved Reserves..................        25,534,000       230,000,000
  Proved developed reserves........        16,300,000       184,955,000
December 31, 2000
  Proved Reserves..................        22,303,000       233,208,000
  Proved developed reserves........        13,923,000       179,697,000


                                      F-30
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
   SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - (continued)
                                   (Unaudited)

     The changes in Proved  Reserves for the years ended December 31, 1998, 1999
and 2000 were as follows:


                                                                     Gas
                                                     Oil         (Thousand
                                                   (Barrels)     Cubic Feet)
                                              ---------------------------------

Reserves at December 31, 1997.............     20,946,000     207,776,000
Purchase of minerals-in-place.............      1,363,000      39,535,000
Sale of minerals-in-place.................         (4,000)              -
Extensions and discoveries................        279,000      12,091,000
Production................................     (1,141,000)    (14,119,000)
Revisions of estimates....................     (4,094,000)    (26,223,000)
                                              ---------------------------------

Reserves at December 31, 1998.............     17,349,000     219,060,000
Purchase of minerals-in-place.............      3,123,000      15,990,000
Sale of minerals-in-place.................        (21,000)       (197,000)
Extensions and discoveries................        164,000       6,068,000
Production................................     (1,311,000)    (19,041,000)
Revisions of estimates....................      6,230,000       8,120,000
                                              ---------------------------------

Reserves at December 31, 1999.............     25,534,000     230,000,000
Purchase of minerals-in-place.............          1,000       2,203,000
Sale of minerals-in-place.................     (3,095,000)    (21,966,000)
Extensions and discoveries................      1,777,000      35,009,000
Production................................     (1,298,000)    (19,579,000)
Revisions of estimates....................       (616,000)       7,541,000
                                              ---------------------------------

Reserves at December 31, 2000.............     22,303,000     233,208,000
                                              ---------------------------------

     The  aggregate  amounts  of  capitalized  costs  relating  to oil  and  gas
producing  activities  and  the  related  accumulated  depreciation,  depletion,
amortization  and  impairment  as of December  31,  2000,  1999 and 1998 were as
follows:
<TABLE>
<CAPTION>
<S>                                                             <C>              <C>              <C>
                                                                     2000             1999              1998
                                                               ----------------------------------------------------
Unproved oil and gas properties................................ $     5,534,000   $     3,567,000   $     1,655,000
Proved properties..............................................     367,822,000       349,510,000       296,545,000
                                                               ----------------------------------------------------

Gross Capitalized Costs........................................     373,356,000       353,077,000       298,200,000
Accumulated depreciation, depletion, amortization and impairment   (124,720,000)     (100,370,000)      (79,194,000)
                                                               ----------------------------------------------------
          Net Capitalized Costs................................ $   248,636,000   $   252,707,000   $   219,006,000
                                                               ====================================================
</TABLE>

     Costs incurred in oil and gas producing  activities,  both  capitalized and
expensed,  during  the years  ended  December  31,  2000,  1999 and 1998 were as
follows:
<TABLE>
<CAPTION>
<S>                                                               <C>             <C>              <C>
                                                                         2000            1999            1998
                                                                    -----------------------------------------------
Property acquisition costs
  Proved properties................................................. $    7,806,000  $   34,478,000  $   36,620,000
  Unproved properties...............................................      1,080,000       1,912,000       1,138,000
Exploration costs...................................................     32,521,000       6,835,000       4,696,000
Development costs...................................................     22,234,000      12,176,000      27,840,000
                                                                    -----------------------------------------------
          Total Costs Incurred...................................... $   63,641,000  $   55,401,000  $   70,294,000
                                                                    ===============================================
</TABLE>

                                      F-31
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
   SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - (continued)
                                   (Unaudited)

     Results of operations  from oil and gas producing  activities for the years
ended December 31, 2000, 1999 and 1998 were as follows:
<TABLE>
<CAPTION>
<S>                                                               <C>             <C>               <C>
                                                                          2000            1999              1998
                                                                   ------------------------------------------------
Oil and gas production revenue.....................................   $ 106,052,000    $ 60,673,493   $ 43,564,728
Production costs...................................................     (28,959,000)    (23,575,241)   (20,682,187)
Depreciation, depletion, amortization and impairment...............     (24,350,000)    (21,176,428)   (63,102,795)
Income taxes.......................................................     (18,460,000)     (5,572,638)    14,077,089
                                                                   ------------------------------------------------
          Results of Operations for Producing Activities              $  34,283,000    $ 10,349,186   $(26,143,165)
                                                                   ================================================
</TABLE>

     The  standardized  measure of  discounted  estimated  future net cash flows
related to proved oil and gas reserves at December 31, 2000,  1999 and 1998 were
as follows:
<TABLE>
<CAPTION>
<S>                                                            <C>               <C>              <C>
                                                                        2000            1999              1998
                                                                -----------------------------------------------------
Future cash inflows............................................. $  2,685,776,000  $ 1,102,673,000  $   625,819,000
Future development costs........................................      (84,158,000)     (52,600,000)     (48,656,000)
Future production costs.........................................     (559,596,000)    (362,365,000)    (229,566,000)
                                                                -----------------------------------------------------
Future net cash flows, before income tax........................    2,042,022,000      687,708,000      347,597,000
Future income taxes.............................................     (607,407,000)    (131,500,000)     (25,671,000)
                                                                -----------------------------------------------------
Future Net Cash Flows...........................................    1,434,615,000      556,208,000      321,926,000
10% annual discount.............................................     (629,692,000)    (240,592,000)    (145,778,000)
                                                                -----------------------------------------------------
    Standardized Measure of Discounted Future Net Cash Flows (a) $    804,923,000  $   315,616,000  $   176,148,000
                                                                =====================================================
</TABLE>

     (a) The standardized  measure of discounted estimated future net cash flows
related to proved oil and gas reserves at December 31, 2000 after giving  effect
to all applicable hedging contracts was $794,680,000.

     The primary  changes in the  standardized  measure of discounted  estimated
future net cash flows for the years ended December 31, 2000,  1999 and 1998 were
as follows:
<TABLE>
<CAPTION>
<S>                                                            <C>              <C>               <C>
                                                                        2000              1999                1998
                                                               -------------------------------------------------------
Purchases of minerals-in-place.................................  $    16,040,000  $    45,321,000  $     46,389,000
Sales of minerals-in-place.....................................      (33,981,000)        (168,000)           (9,000)
Extensions, discoveries and improved recovery, less related costs    208,966,000        8,398,000        10,837,000
Sales of oil and gas produced, net of production costs.........      (77,093,000)     (37,098,000)      (22,883,000)
Development costs incurred during the period...................       22,231,000       12,176,000        27,840,000
Revision of prior estimates:
  Net change in prices and costs...............................      552,634,000      118,271,000       (76,286,000)
  Change in quantity estimates.................................        1,524,000       36,937,000       (55,991,000)
Accretion of discount..........................................       31,562,000       17,615,000        16,977,000
Net change in income taxes.....................................     (232,576,000)     (61,984,000)       59,502,000
                                                               -------------------------------------------------------
                 Net Change....................................  $   489,307,000  $   139,468,000  $      6,376,000
                                                               =======================================================
</TABLE>

     Estimated  future cash inflows are computed by applying  year-end prices of
oil  and  gas to  year-end  quantities  of  Proved  Reserves.  Estimated  future
development and production  costs are determined by estimating the  expenditures
to be incurred in  developing  and  producing the proved oil and gas reserves at
the end of the year,  based on  year-end  costs  and  assuming  continuation  of
existing economic conditions.  Estimated future income tax expense is calculated
by applying year-end statutory tax rates to estimated future pre-tax net

                                      F-32
<PAGE>

                 MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES
   SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES - (continued)
                                  (Unaudited)

     cash flows  related to proved oil and gas  reserves,  less the tax basis of
the properties involved.

     The  assumptions  used  to  compute  the  standardized  measure  are  those
prescribed  by the  Financial  Accounting  Standards  Board and as such,  do not
necessarily reflect the Company's  expectations of actual revenues to be derived
from those reserves nor their present  worth.  The  limitations  inherent in the
reserve quantity  estimation  process are equally applicable to the standardized
measure  computations  since  these  estimates  are the basis for the  valuation
process.

                                      F-33
<PAGE>

Item 9. Changes In and Disagreements With Accountants on Accounting and
          Financial Disclosure. None.

                                    PART III

Item 10. Directors, Executive Officers, Promoters and Control Persons;
           Compliance with Section 16(a) of the Exchange Act

     The following table sets forth the directors,  executive officers and other
significant employees of the Company,  their ages, and all offices and positions
with  the  Company.  Each  director  is  elected  for a  period  of one year and
thereafter serves until his successor is duly elected by the stockholders of the
Company and qualifies.
<TABLE>
<CAPTION>
<S>                              <C>     <C>
 Name                             Age       Title
Gary C. Evans...................  43        Director, President and Chief Executive Officer
Matthew C. Lutz.................  66        Chairman of the Board and Executive Vice President
Richard R. Frazier..............  54        President and Chief Operating Officer of Magnum Hunter
                                            Production, Inc. and Gruy
Chris Tong......................  44        Senior Vice President and Chief Financial Officer
R. Douglas Cronk . . . . . . . .  54        Senior Vice President of Operations of Magnum Hunter Production, Inc.
                                            and Gruy
Morgan F. Johnston..............  40        Vice President, General Counsel and Secretary
David S. Krueger................  51        Vice President and Chief Accounting Officer
Michael McInerney . . . . . . .   59        Vice President, Corporate Development & Investor Relations
Charles R. Erwin................  53        Senior Vice President of Exploration of Magnum Hunter Production, Inc.
                                            and Gruy
Gregory L. Jessup...............  47        Vice President of Land of Magnum Hunter Production, Inc. and Gruy
David M. Keglovits..............  49        Vice President and Controller
Craig Knight....................  44        Vice President of Operations of Hunter Gas Gathering, Inc.
Earl Krieg, Jr. ................  47        Vice President of Engineering of Magnum Hunter Production, Inc. and
                                            Gruy
Gerald W. Bolfing...............  72        Director
Jerry Box.......................  62        Director
Jim Kneale......................  49        Director
David L. Kyle...................  48        Director
Oscar C. Lindemann..............  78        Director
John H. Trescot, Jr.............  75        Director
James E. Upfield................  80        Director
</TABLE>

     Gary C.  Evans has  served as  President,  Chief  Executive  Officer  and a
director of Magnum Hunter  Resources,  Inc. since December 1995 and Chairman and
Chief  Executive  Officer of all of the Magnum Hunter  subsidiaries  since their
formation or  acquisition.  In 1985, Mr. Evans formed the  predecessor  company,
Hunter  Resources,  Inc., that was merged into and formed Magnum Hunter some ten
years later.  From 1981 to 1985,  Mr. Evans was  associated  with the Mercantile
Bank of Canada where he held various  positions  including  Vice  President  and
Manager of the Energy Division of the Southwestern  United States.  From 1978 to
1981,  he served in various  capacities  with  National  Bank of  Commerce  (now
BancTexas,  N.A.) including Credit Manager and Credit Officer.  Mr. Evans serves
on the Board of Directors of Novavax,  Inc., an American Stock  Exchange  listed
pharmaceutical  company.  He  additionally  serves on the board of three private
Texas-based  companies  that Magnum Hunter owns various  minority  interests in,
including(i)  Swanson Consulting Services,  Inc., a geological  consulting firm;
(ii) NGTS, LLC, a natural gas marketing  company and (iii) Aurion  Technologies,
Inc., a company that provides web-enabled  automation to the oil and natural gas
industry.  He also serves as a Trustee of TEL Offshore  Trust, an OTC listed oil
and gas trust of which Magnum Hunter owns an approximate 42% interest.

                                       39
<PAGE>


     Matthew C. Lutz has served as Chairman since March 1997 after having served
as Vice Chairman of the Company since December 1995. Mr. Lutz has also served as
Executive  Vice President  since December 1995. Mr. Lutz held similar  positions
with Hunter from September 1993 until October 1996.  From 1984 through 1992, Mr.
Lutz was Senior Vice President of  Exploration  and on the Board of Directors of
Enserch  Exploration,  Inc. with responsibility for such company's worldwide oil
and gas exploration and development program.  Prior to joining Enserch, Mr. Lutz
spent 28 years with Getty Oil Company.  He advanced  through several  technical,
supervisory  and managerial  positions  which gave him various  responsibilities
including  exploration,   production,  lease  acquisition,   administration  and
financial planning.

     Richard R. Frazier has served as President and Chief  Operating  Officer of
Magnum Hunter  Production,  Inc. and Gruy since January 1994. From 1977 to 1993,
Mr. Frazier was employed by Edisto Resources  Corporation in Dallas,  serving as
Executive Vice President  Exploration and Production from 1983 to 1993, where he
had overall responsibility for its property acquisition,  exploration, drilling,
production,  gas marketing and  engineering  functions.  From 1972 to 1976,  Mr.
Frazier served as District Production Superintendent and Petroleum Engineer with
HNG Oil Company (now Enron Oil & Gas Company) in Midland,  Texas.  Mr. Frazier's
initial  employment,  from 1968 to 1971, was with Amerada Hess  Corporation as a
petroleum  engineer  involved in numerous  projects in Oklahoma  and Texas.  Mr.
Frazier  graduated  in 1970 from the  University  of Tulsa  with a  Bachelor  of
Science  Degree  in  Petroleum  Engineering.  He  is a  registered  Professional
Engineer in Texas and a member of the Society of  Petroleum  Engineers  and many
other professional organizations.

     Chris Tong has served as Senior Vice President and Chief Financial  Officer
since August 1997. Previously,  Mr. Tong was Senior Vice President of Finance of
Tejas Acadian  Holding Company and its  subsidiaries  including Tejas Gas Corp.,
Acadian  Gas  Corporation  and  Transok,  Inc.,  all of which were  wholly-owned
subsidiaries of Tejas Gas  Corporation.  In January 1998,  Tejas Gas Corporation
was acquired by Shell Oil. Mr. Tong held these  positions since August 1996, and
served in other treasury positions with Tejas beginning August 1989. He was also
responsible for managing Tejas' property and liability  insurance.  From 1980 to
1989,  Mr.  Tong  served in various  energy  lending  capacities  with  Canadian
Imperial Bank of Commerce,  Post Oak Bank, and Bankers Trust Company in Houston,
Texas.  Prior to his  banking  career,  Mr.  Tong also  served  over a year with
Superior Oil Company as a Reservoir Engineering  Assistant.  Mr. Tong is a summa
cum laude graduate of the University of  Southwestern  Louisiana with a Bachelor
of Arts degree in Economics and a minor in Mathematics.

     R.  Douglas  Cronk has served as Senior Vice  President of  Operations  for
Magnum Hunter  Production,  Inc. and Gruy since December 1998. He served as Vice
President of Operations  for the two companies  since May 1996 at which time the
Company  acquired  from Mr. Cronk  Rampart  Petroleum,  Inc.,  based in Abilene,
Texas. Rampart had been an active operating and exploration company in the north
central and west Texas region since 1983. Prior to the formation of Rampart, Mr.
Cronk  was  an  independent  oil  and  gas  consultant  in  Houston,  Texas  for
approximately  two years.  From 1974 to 1981,  Mr. Cronk held various  positions
with subsidiaries of Deutsch Corporation of Tulsa, Oklahoma, including Southland
Drilling  and  Production  where  he  became  Vice  President  of  Drilling  and
Production.  Mr. Cronk is a Chemical  Engineer  graduate from the  University of
Tulsa.

     Morgan F. Johnston has served as Vice  President and General  Counsel since
April  1997 and has served as the  Company's  Secretary  since May 1, 1996.  Mr.
Johnston  was in private  practice  as a sole  practitioner  from May 1, 1996 to
April 1, 1997,  specializing in corporate and securities law. From February 1994
to May 1996,  Mr.  Johnston  served  as  general  counsel  for  Millennia,  Inc.
(formerly known as SOI Industries,  Inc.) and Digital Communications  Technology
Corporation,  two American Stock Exchange  listed  companies.  He also served as
general counsel to Halter Capital  Corporation,  a private  consulting firm from
August  1991  to May  1996.  For the  two  years  prior  to  August  1991 he was
securities  counsel for Motel 6 L.P., a New York Stock Exchange  listed company.
Mr. Johnston  graduated cum laude from Texas Tech Law School in May 1986 and was
also a member of the Texas Tech Law Review.  He is  licensed to practice  law in
the State of Texas.

                                       40
<PAGE>

     David S. Krueger has served as Vice President and Chief Accounting  Officer
of the Company since January 1997. Mr.  Krueger acted as Vice  President-Finance
of Cimarron Gas Holding Co., a gas processing and natural gas liquids  marketing
company in Tulsa,  Oklahoma,  from April 1992 until  January  1997. He served as
Vice  President/  Controller  of American  Central Gas  Companies,  Inc.,  a gas
gathering, processing and marketing company from May 1988 until April 1992. From
1974 to 1986, Mr. Krueger served in various managerial  capacities for Southland
Energy  Corporation.  From 1971 to 1973, Mr. Krueger was a staff accountant with
Arthur Andersen LLP. Mr. Krueger, a certified public accountant,  graduated from
the  University of Arkansas with a B.S./B.A.  degree in Business  Administration
and earned his M.B.A. from the University of Tulsa.

     Michael P. McInerney has served as Vice President,  Corporate Development &
Investor  Relations  of the Company  since  October  1997.  Prior to joining the
Company,  Mr. McInerney owned Energy Advisors,  Inc., an energy consulting firm,
from June 1993 until  October 1997.  Mr.  McInerney was employed from 1981 until
June 1993 by Triton Energy Corporation, an independent energy company, where his
responsibilities   included  investor  relations,   acquisitions  and  corporate
planning.  Before joining Triton Energy  Corporation,  Mr. McInerney served nine
years in various financial  management positions with American Natural Resources
Company,  a  gas  transmission  and  distribution  corporation.   Mr.  McInerney
graduated from the University of Michigan with a B.B.A.

     Charles R. Erwin has served as Senior Vice  President  of  Exploration  for
Magnum Hunter  Production,  Inc. and Gruy  Petroleum  Management  Co. since July
2000. He became Vice President of Exploration for Magnum Hunter Production, Inc.
and Gruy Petroleum Management Co. in January 2000. Mr. Erwin initially served as
Manager of Exploration for Gruy Petroleum  Management Co. beginning May of 1999.
Mr.  Erwin  received a Masters in Geology  from the  University  of  Wisconsin -
Milwaukee. He has 27 years experience in the oil and gas industry. Prior to Gruy
Petroleum  Management Co., Mr. Erwin worked for Enserch Exploration for 22 years
holding  various  positions   including   Exploration   Manager  -  East  Texas,
Exploration  Manager - Texas and Louisiana  Gulf Coast and Director  Exploration
Offshore and International.

     Gregory  L.  Jessup  has been  Vice  President  of Land for  Magnum  Hunter
Production,  Inc., a wholly-owned subsidiary of the Company and Gruy since April
17, 1998.  Mr.  Jessup  joined the Company as Land Manager on May 1, 1997.  From
1982  until  joining  the  Company,  Mr.  Jessup  served as Land  Manager of Ken
Petroleum  Corporation of Dallas managing its Land and Regulatory  Department as
well as managing  its crude oil  marketing  business.  During his tenure as Land
Manager, Mr. Jessup has been actively involved in all phases of land operations,
including  negotiations,  acquisitions,  and administration.  Mr. Jessup holds a
Bachelor  of  Business  Administration  degree in  Management  from  Texas  Tech
University and is a Certified Professional Landman.

     David M.  Keglovits  has served as Vice  President  and  Controller  of the
Company and its subsidiaries  since 1999. Prior to 1999. Mr. Keglovits served as
Vice President and Controller of Gruy. Mr.  Keglovits  joined Gruy in March 1977
as an  accountant  before  holding the  positions  of Assistant  Controller  and
Controller.  From December 1974 to December 1976, Mr.  Keglovits was employed by
Bell  Helicopter  International  in its financial  management  office in Tehran,
Iran.  Mr.  Keglovits was graduated  with honors from the University of Texas at
Austin with a B.B.A. in Accounting.

     Craig  Knight has served as Vice  President  of  Operations  for Hunter Gas
Gathering,  Inc.  since March 1998.  Prior to joining the Company Mr. Knight was
employed by MidCon Corp.  and its affiliates  since 1979 in various  capacities.
From 1995 to his departure  from MidCon he served as the Sr.  Business  Manager,
Gathering and Processing for MidCon Gas Products Corp. where he managed MidCon's
gathering and  processing  activities in the Panhandle and Permian Basin regions
of Texas. From 1992 -1994, he served as an account manager of the Electric Power
Sector  Start-up Group for MidCon Gas Services Corp and as Manager - West Region
for MidCon  Marketing Corp. Mr. Knight graduated from Texas Tech University with
a B.S. in Engineering Technology with Construction  Specialty.  He also received
his M.B.A. in Executive Programs from University of Houston in 1989.

                                       41
<PAGE>

     Earl  Krieg  has  served  as  Manager  of  Engineering  for Gruy  Petroleum
Management Co. since May of 1999. Mr. Krieg became Vice President of Engineering
for Magnum  Hunter  Production,  Inc.  and Gruy in January  2000.  Mr. Krieg was
employed  by The Wiser Oil  Company  for the five  years  prior to  joining  the
Company in various  capacities  including  Manager of Operations  and Manager of
Secondary  Recovery.  Mr. Krieg has 26 years in various  reservoir  engineering,
operations,  acquisitions  and  management  roles with Chevron,  General  Crude,
Edisto  and most  recently  The Wiser Oil  Company.  Mr.  Krieg is a  Registered
Professional  Engineer in Texas and was an officer in the  Society of  Petroleum
Evaluation  Engineers in 1989. Mr. Krieg  graduated from Texas A&M University in
1975 with a B.S. degree in petroleum engineering.

     Gerald W. Bolfing has been a director of the Company since  December  1995.
Mr. Bolfing was appointed a director of Hunter in August 1993. He is an investor
in the  oil  and gas  business  and a past  officer  of one of  Hunter's  former
subsidiaries.  From 1962 to 1980,  Mr.  Bolfing  was a partner in  Bolfing  Food
Stores in Waco, Texas. During this time, he also joined American Service Company
in Atlanta,  Georgia  from 1964 to 1965,  and was active with Cable  Advertising
Systems,  Inc.  of  Kerrville,  Texas  from  1978 to  1981.  He  joined a Hunter
subsidiary in the well servicing business in 1981 where he remained active until
its  divestiture  in 1992.  Mr.  Bolfing is on the board of directors of Capital
Marketing Corporation of Hurst, Texas.

     Jerry Box has served as a director  of the Company  since March 1999.  From
February  1998 to March  1999 he  served in the  position  of  President,  Chief
Operating  Officer and Director of Oryx Energy Company  ("Oryx").  From December
1995 to  February  1998 he was  Executive  Vice  President  and Chief  Operating
Officer of Oryx. From December 1994 through November 1995 he served as Executive
Vice  President,  Exploration and Production of Oryx.  Previously,  he served as
Senior Vice  President,  Exploration  and  Production of Oryx.  Mr. Box attended
Louisiana Tech  University,  where he received B.S. and M.S. degrees in geology,
and is also a graduate of the Program for Management  Development at the Harvard
University  Graduate  School of  Business  Administration.  Mr. Box served as an
officer in the U. S. Air Force from 1961 to 1966.  Mr. Box is a former member of
the Policy Committee of the U. S. Department of the Interior's Outer Continental
Shelf Advisory Board, past Chairman and Vice-Chairman of the American  Petroleum
Institute's  Exploration Affairs subcommittee,  a former President of the Dallas
Petroleum Club and a member of the Independent Petroleum Association of America.

     Jim Kneale has served as a director of the Company  since  September  2000.
Mr. Kneale is currently  employed by ONEOK, Inc., as senior vice president since
January 18, 2001 and is responsible for the finance,  tax and  accounting,  risk
management and risk control functions for ONEOK. Mr. Kneale joined ONEOK in 1981
as vice president of ONEOK Drilling Company.  He became vice president of Energy
Companies of ONEOK later in 1981 and was named vice  president of accounting for
Oklahoma  Natural Gas Company in 1992. Mr. Kneale became vice president of Tulsa
District in 1994,  vice president for ONEOK  Resources in 1996, and president of
Oklahoma  Natural  Gas in 1997.  He was elected to the chief  financial  officer
position in 1999. Mr. Kneale is a member of the American  Institute of Certified
Public  Accountants  and the  Oklahoma  Society  of CPAs.  He is a  graduate  of
Leadership Oklahoma and Leadership Tulsa and is a Leadership Tulsa Paragon Award
winner.  Mr.  Kneale  serves on the Board of  Directors  of the YMCA of  Greater
Tulsa,  the Tulsa  Boys'  Home,  Tulsa  Community  College  Foundation,  and the
Advisory Board of the Oklahoma Blood Institute.  A certified public  accountant,
Mr.  Kneale  received his  accounting  degree from West Texas A&M  University in
1973.

     David L. Kyle has served as a director of the Company since  February 1999.
Mr.  Kyle is  currently  employed  by ONEOK  Inc.,  as its  President  and Chief
Operating  Officer.  Mr. Kyle was employed by Oklahoma  Natural Gas  Company,  a
division of ONEOK Inc., in 1974 as an engineer trainee. He served in a number of
positions prior to being elected Vice President of Gas Supply in September 1986,
and Executive Vice President in May 1990. He was elected  President in September
1994. He was elected  President of ONEOK Inc.  effective  September 1997. He has
the management  responsibility  for all of the  unregulated  companies of ONEOK,
Inc. He received a B.S.  degree in industrial  engineering  and management  from
Oklahoma  State  University  in 1974. He received an MBA degree in 1987 from The
University  of Tulsa,  and is a graduate of the Advanced  Management  Program at
Harvard Business School.

                                       42
<PAGE>

     Oscar C.  Lindemann has served as a director of the Company since  December
1995. Mr.  Lindemann was previously a director of Hunter,  having been appointed
in November  1995. Mr.  Lindemann has over 40 years  experience in the financial
industry.  Mr.  Lindemann began his banking career with the Texas Bank and Trust
in Dallas,  Texas in 1951.  He served  the bank  until 1977 in many  capacities,
including Chief Executive Officer and Chairman of the Board. Since leaving Texas
Bank and Trust,  he has served as Vice Chairman of both the United National Bank
and the National Bank of Commerce, also in Dallas. Mr. Lindemann has also served
as a consultant to the banking industry.  He retired from commercial  banking in
1987. Mr. Lindemann is a former President of the Texas Bankers Association,  and
a former state  representative  to the American  Bankers  Association.  He was a
Founding  Director  and Board  Member of VISA,  and a member of the Reserve City
Bankers  Association.  He has served as an instructor  at both the  Southwestern
Graduate  School of Banking at Southern  Methodist  University and the School of
Banking of the South at Louisiana State University.

     John H.  Trescot,  Jr. has served as a director of the  Company  since June
1997. Mr. Trescot is the principal of AWA Management  Corporation,  a consulting
firm  specializing  in financial  evaluations for companies and entities such as
OPIC (Overseas  Private  Investment  Corp.).  Mr. Trescot began his professional
career as an engineer with Shell Oil Company.  Later,  Mr. Trescot joined Hudson
Pulp & Paper  Corp.  (now a part of  Georgia-Pacific  Corp.)  where he served 19
years in various  positions  in woodlands  and pulp and paper,  advancing to the
position of Senior Vice President,  Southern Operations. Mr. Trescot then became
Vice President of The Charter Company,  a multi-billion  dollar corporation with
operations in oil, communications and insurance. In 1979, Mr. Trescot became the
Chief  Executive  Officer of JARI,  a timber,  pulp and mining  operation in the
Amazon Basin of Brazil owned by billionaire D.K. Ludwig.  During 1982-89,  while
he was the Chief Executive  Officer of TOT Drilling Corp., TOT drilled many deep
wells in west Texas and New Mexico for major and independent  oil companies.  He
is a bank director and  multi-engine  pilot. Mr. Trescot received his BME degree
from Clemson University and his MBA from the Harvard Business School.

     James E.  Upfield has served as a director of the  Company  since  December
1995. Mr. Upfield was appointed a director of Hunter in August 1992. Mr. Upfield
is Chairman of Temtex Industries,  Inc. based in Dallas, Texas, a public company
that produces consumer hard goods and building  materials.  In 1969, Mr. Upfield
served on a select  Presidential  Committee  serving  postal  operations  of the
United States of America.  He later accepted the  responsibility  for the Dallas
region,  which encompassed  Texas and Louisiana.  From 1959 to 1967, Mr. Upfield
was President of Baifield Industries,  Inc. ("Baifield") and its predecessor,  a
company he founded in 1949 which  merged  with  Baifield in 1963.  Baifield  was
engaged in prime  government  contracts for military  systems and sub-systems in
the production of high-strength, light-weight metal products.

                                       43
<PAGE>

Item 11.          Executive Compensation.

     The  following  table  contains   information  with  respect  to  all  cash
compensation  paid or accrued by the Company  during the past three fiscal years
to the Company's Chief Executive Officer and each person serving as an executive
officer of the Company on December 31, 2000.
<TABLE>
<CAPTION>
<S>                        <C>     <C>       <C>          <C>              <C>          <C>      <C>         <C>
                                                                                 Long Term Compensation
                                     Annual Compensation                      Awards               Payout
           (a)               (b)      (c)         (d)            (e)            (f)       (g)        (h)           (i)
          Name,                                                 Other                    Number
        Principal                                               Annual      Restricted  Options      LTP        All Other
         Position           Year     Salary      Bonus     Compensation (a)    Stock      SARs     Payouts    Compensation
         --------           ----     ------      -----     -------------       -----      ----     -------    ------------
Gary C. Evans               2000    $300,000   $400,000        $ 7,500           -         -          -        $19,933 (b)
President and CEO           1999    $250,000   $250,000        $ 7,500           -         -          -        $19,342 (b)
                            1998    $250,000   $300,000           -              -         -          -             -

Matthew C. Lutz             2000    $175,000   $300,000        $ 8,400           -         -          -             -
Executive V.P. and          1999    $150,000   $125,000        $ 6,000           -         -          -             -
Chairman                    1998    $156,000   $100,000           -              -         -          -             -

Richard R. Frazier          2000    $175,000   $125,000        $ 6,000           -         -          -             -
President of                1999    $150,000   $ 75,000        $ 4,200           -         -          -             -
Magnum Hunter               1998    $154,200   $ 50,000           -              -         -          -             -
Production, Inc.

Chris Tong                  2000    $160,000   $ 65,000        $ 6,000           -         -          -             -
Senior Vice President &     1999    $150,000   $ 35,000        $ 6,000           -         -          -             -
Chief Financial Officer     1998    $156,000   $ 30,000           -              -         -          -             -

R. Douglas Cronk            2000    $122,500   $ 65,000        $ 6,000           -         -          -             -
Senior V.P. of Magnum       1999    $115,000   $ 25,000        $ 4,200           -         -          -             -
Hunter Production, Inc.     1998    $104,200   $ 20,000           -              -         -          -             -

Charles R. Erwin (c)        2000    $113,423   $125,000        $ 5,100           -         -          -             -
Senior V.P. of Magnum       1999    $ 90,000    $ 7,500           -              -         -          -             -
Hunter Production, Inc.     1998       -           -              -              -         -          -             -
</TABLE>

---------------------

     (a)  Other  compensation  consists  of a  vehicle  allowance  paid  to  the
employee.

     (b) Mr. Evans receives compensation for acting as an individual Trustee for
the TEL Offshore Trust.

     (c) Mr. Erwin was hired in May 1999.

                                       44
<PAGE>

                      Option/SAR Grants in Last Fiscal Year
<TABLE>
<CAPTION>
<S>                 <C>           <C>              <C>               <C>         <C>                <C>          <C>
                                                                                  Potential realizable value at  Alternative to
                                                                                  assumed annual rates of stock  (f) and (g):
                                                                                  price appreciation for option   grant date
                                  Individual Grants                                           term                   value
-------------------------------------------------------------------------------- -----------------------------  -------------
       Name          Number of     Percent of total  Exercise or base  Expiration      5% ($)         10% ($)     Grant date
                     securities     options/SARs     price ($/Sh)        date                                     present value
                     underlying     granted to                                                                     $
                     Options/SARs   employees in
                      granted (#)   fiscal year

        (a)               (b)             (c)            (d)            (e)            (f)            (g)            (f)
-------------------  -------------- --------------- --------------  ------------ --------------- -------------  -------------
Gary C. Evans               300,000       19%          $7.9375        12/08/10                                      1,697,460
Matthew C. Lutz             200,000       13%          $7.9375        12/08/10                                      1,131,640
Richard R. Frazier          100,000        6%          $7.9375        12/08/10                                        565,820
Charles R. Erwin            100,000        6%          $7.9375        12/08/10                                        565,820
R. Douglas Cronk             50,000        3%          $7.9375        12/08/10                                        282,910
Chris Tong                   40,000        3%          $7.9375        12/08/10                                        226,328
</TABLE>

Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values
<TABLE>
<CAPTION>
<S>                      <C>                    <C>              <C>                     <C>
                                                                  Number of securities    Value of unexercised in-
                                                                 underlying unexercised    the-money options/SARs
                                                                  options/SARs at fiscal   at fiscal year-end ($)
                                                                       year-end (#)


                         Shares acquired on         Value              Exercisable/              Exercisable/
         Name               exercise (#)         Realized ($)          unexercisable            unexercisable
         (a)                    (b)                 (c)                    (d)                      (e)
----------------------------------------------------------------------------------------------------------------------
   Gary C. Evans               500,000            $1,375,000        310,000 / 290,000     $1,949,850 / $1,935,900
   Matthew C. Lutz                -                   -             575,000 / 250,000     $3,873,250 / $1,207,500
   Richard R. Frazier             -                   -             270,000 / 155,000     $1,809,400 / $  292,050
   Charles R. Erwin             14,000            $ 103,840          24,000 /  92,000     $   90,690 / $  329,520
   R. Douglas Cronk               -                   -              82,000 /  73,000     $  527,045 / $  389,130
   Chris Tong                     -                   -             161,000 /  89,000     $1,028,972 / $  503,840
</TABLE>

       Compensation of Directors

     The Company has nine individuals who serve as directors, seven of which are
independent.  Two of these directors receive  compensation with respect to their
services and in their  capacities  as  executive  officers of the Company and no
additional  compensation  has  historically  been paid for their services to the
Company as directors. The other seven directors of the Company are not employees
of the Company and receive no compensation for their services as directors other
than as stated  below.  For fiscal  years 1999 and 2000,  independent  directors
received a $10,000  retainer for being a board  member and in addition  received
$1,000 per meeting attended. Each new independent director added to the board in
fiscal year 1999 was granted an option to acquire 25,000 shares of the Company's
common  stock at an exercise  price not less than the market price of the common
stock on the date of grant. In addition, for the fiscal years 1999 and 2000 each
independent  director  was granted  stock  options to acquire  10,000 and 15,000
shares, respectively,

                                       45
<PAGE>

     of the Company's common stock at an exercise price not less than the market
price  of the  common  stock  on the  date  of  grant.  For  fiscal  year  2001,
independent  directors will receive a $15,000  retainer for being a board member
and in addition will receive $1,500 per meeting  attended and $500 per committee
meeting attended. Other than the compensation stated herein, the Company has not
entered into any arrangement,  including consulting contracts,  in consideration
of the director's service on the board.

               Employment Contracts and Termination of Employment
                       and Change-in-Control Arrangements

     Mr. Gary C. Evans,  Mr. Matthew C. Lutz, Mr. Richard R. Frazier,  Mr. Chris
Tong,  Mr. R.  Douglas  Cronk and Mr.  Charles  R.  Erwin  each have  employment
agreements with the Company. Mr. Evans' agreement terminates January 1, 2005 and
continues  thereafter  on a year to year  basis  and  provides  for a salary  of
$300,000 per annum unless increased by the Board. Mr. Evans' salary for the year
2001 is $350,000.  Mr. Lutz's agreement terminates January 1, 2005 and continues
thereafter  on a year to year basis and  provides  for a salary of $175,000  per
annum unless  increased  by the Board.  Mr.  Lutz's  salary for the year 2001 is
$245,000.  Mr.  Frazier's  agreement  terminates  January 1, 2005 and  continues
thereafter  on a year to year basis and  provides  for a salary of $175,000  per
annum unless  increased by the Board.  Mr. Frazier's salary for the year 2001 is
$190,000.  Mr.  Tong's  agreement  terminates  January  1,  2003  and  continues
thereafter  on a year to year basis and  provides  for a salary of $160,000  per
annum unless  increased  by the Board.  Mr.  Tong's  salary for the year 2001 is
$165,000.  Mr.  Cronk's  agreement  terminates  January  1,  2003 and  continues
thereafter  on a year to year basis and  provides  for a salary of $122,500  per
annum unless  increased by the Board.  Mr.  Cronk's  salary for the year 2001 is
$138,000.  Mr.  Erwin's  agreement  terminates  January  1,  2003 and  continues
thereafter  on a year to year basis and  provides  for a salary of $125,000  per
annum unless  increased by the Board.  Mr.  Erwin's  salary for the year 2001 is
$145,000. All of the agreements provide that the same benefits supplied to other
Company employees shall be available to the employee.  The employment agreements
also contain, among other things, covenants by the employee that in the event of
termination,  he will not compete with the Company in certain geographical areas
or hire any  employees of the Company for a period of two years after  cessation
of employment.

     In  addition,  all  of the  agreements  contain  a  provision  that  upon a
change-in-control  of the Company and the  employee's  position is terminated or
the  employee  leaves for "good  cause",  the  employee  is entitled to receive,
immediately in one lump sum, certain compensation. In the case of Mr. Evans, Mr.
Lutz and Mr. Frazier, the employee shall receive three times the employee's base
salary,  bonus for the last fiscal year and any other  compensation  received by
him in the last fiscal year. In the case of Mr. Tong and Mr. Cronk, the employee
shall receive the employee's base salary, bonus for the last fiscal year and any
other  compensation  received by him in the last fiscal year  multiplied by two.
Also, any medical, dental and group life insurance covering the employee and his
dependents  shall  continue  until  the  earlier  of (i)  12  months  after  the
change-in-control  or (ii) the date the employee  becomes a  participant  in the
group insurance benefit program of a new employer.  The Company also has key man
life insurance on Mr. Evans in the amount of $12,000,000.

                                       46
<PAGE>

Item 12.         Security Ownership of Certain Beneficial Owners and Management.

     The following table sets forth certain information as of February 28, 2001,
regarding  the share  ownership  of the Company by (i) each person  known to the
Company to be the beneficial owner of more than 5% of the outstanding  shares of
Common Stock of the  Company,  (ii) each  director,  (iii) the  Company's  Chief
Executive Officer and the four other most highly compensated  executive officers
of the Company, and (iv) all directors and executive officers of the Company, as
a group. None of the directors or executive officers named below, as of February
28, 2001, owned any shares of the Company's Series A Preferred Stock or its 1996
Series A Convertible  Preferred  Stock. The business address of each officer and
director  listed  below is:  c/o Magnum  Hunter  Resources,  Inc.,  600 East Las
Colinas Blvd., Suite 1100, Irving, Texas 75039.
<TABLE>
<CAPTION>
<S>                                                                       <C>                     <C>
                                                                                       Common Stock
                                                                                     Beneficially Owned
                                                                          Number of                  Percent
                             Name                                          Shares                 of Class (o)
Directors and Executive Officers
       Gary C. Evans ..........................................           2,856,073 (a)                 7.8%
       Matthew C. Lutz.........................................             833,229 (b)                 2.3%
       Richard R. Frazier......................................             333,115 (c)                    *
       Chris Tong..............................................             169,933 (d)                    *
       R. Douglas Cronk .......................................             135,768 (e)                    *
       Charles R. Erwin........................................              24,000 (f)                    *
       Gerald W. Bolfing.......................................             457,799 (g)                 1.2%
       Jerry Box...............................................              40,902 (h)                    *
       Oscar C. Lindemann......................................              43,902 (i)                    *
       John H. Trescot, Jr.....................................             125,479 (j)                    *
       James E. Upfield.......................................              124,392 (k)                    *
       David L. Kyle ..........................................              45,342 (l)                    *
       Jim Kneale .............................................               4,000 (m)                    *
       All directors and executive officers as a group
       (13 persons)............................................           5,193,934                    13.8%
Beneficial owners of 5 percent or more
(excluding persons named above)
       ONEOK Resources Company
       100 W. Fifth Street
       Tulsa, OK 74103-4298 ...................................           7,936,507                    22.4%
       Janus Capital Corporation
       100 Fillmore St., Suite 300
       Denver, CO.  80206......................................           1,505,475 (n)                 4.2%
</TABLE>

------------

       *       Less than one percent.

     (a) Includes  310,000  shares of common stock issuable upon the exercise of
certain  currently  exercisable  options.  Also  includes  494,921  common stock
purchase warrants which are currently  exercisable.  Also includes 17,024 shares
held in the name of Jacquelyn Evelyn Enterprises, Inc., a corporation whose sole
shareholder  is Mr.  Evans' wife.  Mr.  Evans  disclaims  any  ownership in such
securities other than those in which he has an economic interest.

     (b) Includes  575,000  shares of common stock issuable upon the exercise of
certain  currently  exercisable  options.  Also  includes  49,641  common  stock
purchase warrants which are currently exercisable.

     (c) Includes  270,000  shares of common stock issuable upon the exercise of
certain currently exercisable options.

                                       47
<PAGE>

     (d) Includes  160,000  shares of common stock issuable upon the exercise of
certain currently exercisable options.

     (e) Includes  82,000  shares of common stock  issuable upon the exercise of
certain currently exercisable options.

     (f)  Includes24,000  shares of common stock  issuable  upon the exercise of
certain currently exercisable options.

     (g) Includes  17,000  shares of common stock  issuable upon the exercise of
certain  currently  exercisable  options.  Also  includes  84,339  common  stock
purchase warrants which are currently exercisable.

     (h) Includes  23,000  shares of common stock  issuable upon the exercise of
certain currently exercisable options.

     (i) Includes  17,000  shares of common stock  issuable upon the exercise of
certain currently exercisable options.

     (j) Includes  42,000  shares of common stock  issuable upon the exercise of
certain currently exercisable options.

     (k) Includes  3,000 shares of common  stock  issuable  upon the exercise of
certain  currently  exercisable  options.  Also  includes  15,848  common  stock
purchase warrants which are currently exercisable.

     (l) Includes  28,000  shares of common stock  issuable upon the exercise of
certain currently exercisable options.

     (m) Includes  3,000 shares of common  stock  issuable  upon the exercise of
certain currently exercisable options.

     (n) Based on Schedule 13G filed by Janus  Capital  Corporation  on February
15, 2001.

     (o) Percentage is calculated on the number of shares outstanding plus those
shares deemed outstanding under Rule 13d-3(d)(1) under the Exchange Act.

Item 13. Certain Relationships and Related Transactions.

     The  Company's  Board of  Directors  authorized a loan of up to $371,860 be
made available to Gary C. Evans,  President and Chief  Executive  Officer of the
Company,  as  part of his  compensation  package.  The  balance  outstanding  at
December 31, 1999 was $371,860 and bears interest at 10% and is due December 31,
2000.  On January  7, 2000 Mr.  Evans  repaid  $225,000  on the loan,  leaving a
principal balance of $146,860.  On April 17, 2000 Mr. Evans re-borrowed $100,000
under this loan, and on August 18, 2000 he repaid  $258,731,  including  accrued
interest,  bringing the balance to zero. On December 28, 2000 Mr. Evans borrowed
$294,938,  which was the balance  owed to the  Company on December  31, 2000 and
included in notes  receivable  from  affiliate.  On January  15, 2001 Mr.  Evans
repaid $295,261, including accrued interest, bringing the balance to zero.

     On November 28, 2000,  Mr.  Matthew C. Lutz,  Chairman and  Executive  Vice
President of the Company, borrowed $65,000 from the Company with the approval of
the Board of Directors. On January 15, 2001, Mr. Lutz repaid the loan, including
accrued interest.

     During 1998, the Company  acquired  certain shares of a publicly traded oil
and gas company  from Mr. Gary C. Evans at Mr.  Evans' cost basis in such shares
of stock. The shares were purchased for a total of $442,019. The Company has the
right through December 31, 2001 to cause Mr. Evans to repurchase the shares back
from the Company at the equivalent  price that the Company  purchased the shares
from Mr. Evans.

                                       48
<PAGE>

                                    GLOSSARY

     The terms defined in this glossary are used throughout this Form 10-K.

     Bbl. One stock tank barrel,  or 42 U.S. gallons liquid volume,  used herein
in reference to oil or other liquid hydrocarbons.

     Bbl/d. One barrel of oil or other liquid hydrocarbons per day.

     Bcf. One billion cubic feet of gas.

     Bcf/d. One billion cubic feet of gas per day.

     Bcfe. One billion cubic feet of Natural Gas Equivalents  converting one Bbl
of oil to six Mcf of gas.

     Btu. British Thermal Unit, the quantity of heat required to raise one pound
of water by one degree Fahrenheit.

     Commercially productive well. A drilled well whose expected total cash flow
equals or exceeds the total  projected costs and expenses  (including  return on
investment) associated with its production over its lifetime.

     Developed Acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.

     Development  Well. A well  drilled  within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.

     Drill site. A well to be drilled  based on existing  Company  knowledge and
analysis of the geologic,  geophysical and engineering  data; no proved reserves
exist prior to drilling.

     Dry Hole. A well found to be  incapable  of producing  either oil or gas in
sufficient quantities to justify completion as an oil or gas well.

     Exploratory  Well.  A well  drilled  to find and  produce  oil or gas in an
unproved  area,  to find a new  reservoir  in a  field  previously  found  to be
productive of oil or gas in another reservoir, or to extend a known reservoir.

     Gross Acres or Gross Wells.  The total acres or wells,  as the case may be,
in which a working interest is owned.

     In-fill  Well.  A well  drilled  between  known  producing  wells to better
exploit the reservoir.

     Mbbl. One thousand barrels of oil or other liquid hydrocarbons.

     Mcf. One thousand cubic feet of gas.

     Mcfe. One thousand cubic feet of Natural Gas Equivalents converting one Bbl
of oil to six Mcf of gas.

     Mcfe/d. Mcfe per day.

     MMBbl. One million barrels of oil or other liquid hydrocarbons.

     MMBtu. One million Btu.

     MMcf. One million cubic feet of gas.

     MMcfe. One million cubic feet of Natural Gas Equivalents converting one Bbl
of oil to six Mcf of gas.

                                       49
<PAGE>

     MMcf/d. One million cubic feet of gas per day.

     Natural Gas Equivalent.  The amount of gas having the same Btu content as a
given quantity of oil, with one Bbl of oil being converted to six Mcf of gas.

     Net Acres or Net Wells. The sum of the fractional  working  interests owned
in gross acres or gross wells.

     Net Revenue  Interest.  A share of the Working  Interest that does not bear
any portion of the expense of drilling and completing a well and that represents
the holder's share of production after  satisfaction of all royalty,  overriding
royalty, oil payments and other nonoperating interests.

     Productive  Well. A well that is producing oil or gas or that is capable of
production in paying quantities.

     Non-Producing  Reserves.  Proved  Developed  Reserves  that  consist of (i)
Proved  Reserves  from wells  which have been  completed  and tested but are not
producing due to minor  completion  problems  which are expected to be corrected
and/or (ii) Proved  Reserves  currently  behind-the-pipe  in existing  wells and
which are expected to be productive due to both the well log characteristics and
analogous production in the immediate vicinity of the wells.

     Producing  Reserves.  Proved Developed  Reserves that can be expected to be
recovered  from  currently  producing  zones under the  continuation  of present
operating methods.

     Proved  Developed  Reserves.  Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.

     Proved  Reserves.  The estimated  quantities of crude oil,  natural gas and
natural gas liquids which  geological  and  engineering  data  demonstrate  with
reasonable  certainty to be  recoverable  in future years from known  reservoirs
under existing  economic and operating  conditions,  i.e. prices and costs as of
the date the  estimate  is made.  Prices  include  consideration  of  changes in
existing  prices  provided  only  by  contractual   arrangements,   but  not  on
escalations based upon future conditions.

     (i) Reservoirs are considered proved if economic producibility is supported
by  either  actual  production  or  conclusive  formation  test.  The  area of a
reservoir considered proved includes (A) that portion delineated by drilling and
defined by gas-oil and/or  oil-water  contacts,  if any; and (B) the immediately
adjoining  portions  not yet  drilled,  but  which can be  reasonably  judged as
economically  productive on the basis of available  geological  and  engineering
data.  In the  absence  of  information  on fluid  contacts,  the  lowest  known
structural  occurrence  of  hydrocarbons  controls the lower proved limit of the
reservoir.

     (ii) Reserves  which can be produced  economically  through  application of
improved  recovery  techniques  (such as fluid  injection)  are  included in the
"proved"  classification  when  successful  testing by a pilot  project,  or the
operation of an installed  program in the  reservoir,  provides  support for the
engineering analysis on which the project or program was based.

     (iii)  Estimates of proved  reserves do not include the following:  (A) oil
that may become available form known reservoirs but is classified  separately as
"indicated  additional  reserves";  (B) crude oil,  natural gas, and natural gas
liquids,  the  recovery  of which is  subject  to  reasonable  doubt  because of
uncertainty as to geology, reservoir  characteristics,  or economic factors; (C)
crude oil,  natural gas,  and natural gas  liquids,  that may occur in undrilled
prospects;  and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.

     Proved  Undeveloped  Reserves.  Reserves  that are expected to be recovered
from new wells on undrilled  acreage,  or from existing wells where a relatively
major expenditure is required for recompletion.

     PV-10.  The  present  value  of  Proved  Reserves  is an  estimate  of  the
discounted  future net cash flows from each of the  properties  at December  31,
2000, or as otherwise indicated.  Net cash flow is defined as net revenues less,
after  deducting

                                       50
<PAGE>

     production  and ad  valorem  taxes,  future  capital  costs  and  operating
expenses, but before deducting federal income taxes. As required by rules of the
Commission,  the future net cash flows have been discounted at an annual rate of
10% to determine  their "present  value." The present value is shown to indicate
the  effect  of time on the  value  of the  revenue  stream  and  should  not be
construed as being the fair market value of the  properties.  In accordance with
Commission rules, estimates have been made using constant oil and gas prices and
operating costs, at December 31, 2000, or as otherwise indicated.

     Recompletion.  The completion  for production of an existing  wellbore in a
different  formation  or  producing  horizon  from  that in  which  the well was
previously completed.

     Reserve Life. The estimated  productive  life of a proved  reservoir  based
upon the  economic  limit of such  reservoir  producing  hydrocarbons  in paying
quantities assuming certain price and cost parameters. For purposes of this Form
10-K,  reserve life is  calculated  by dividing the Proved  Reserves (on an Mcfe
basis) at the end of the period by projected  production volumes for the next 12
months.

     Royalty  Interest.  An interest in an oil and gas  property  entitling  the
owner to a share of oil and gas production free of cost of production.

     Successes  and  successful.  In  the  context  of   exploratory/development
drilling, a well that is a commercially productive well.

     Undeveloped Acreage.  Lease acreage on which wells have not been drilled or
completed to a point that would permit the  production of commercial  quantities
of oil and gas regardless of whether such acreage contains Proved Reserves.

     Working Interest.  The operating interest that gives the owner the right to
drill,  produce and conduct operating  activities on the property and a share of
production, subject to all royalties, overriding royalties and other burdens and
to all  costs  of  exploration,  development  and  operations  and all  risks in
connection therewith.

                                       51
<PAGE>

Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.

     (a) The following documents are filed as part of this report:

1.  Financial Statements

     Independent Auditors' Report............................................F-1

     Financial Statements:

             Consolidated Balance Sheets at December 31, 2000 and 1999.......F-2

             Consolidated Statements of Operations and Comprehensive Income
               for the Years Ended December 31, 2000, 1999 and 1998..........F-3

             Consolidated Statements of Stockholders' Equity for the
               Years Ended December 31, 2000, 1999 and 1998..................F-4

             Consolidated Statements of Cash Flows for the Years
               Ended December 31, 2000, 1999 and 1998........................F-5

     Notes to Consolidated Financial Statements..............................F-6

     Supplemental Information (Unaudited)...................................F-30

2.  Financial Statement Schedule

     We have  included on page 55 of this Annual  Report on Form 10-K  Financial
Statement Schedule II, Valuation and Qualifying Accounts.


                                       52
<PAGE>

3.  Exhibits
<TABLE>
<CAPTION>
<S>          <C>

Number        Description of Exhibit
-------       ----------------------

3.1 & 4.1     Articles of Incorporation (Incorporated by reference to Registration Statement on Form S-18, File No.
              33-30298-D)

3.2 & 4.2     Articles of Amendment to Articles of Incorporation (Incorporated by reference to Form 10-K for the year
              ended December 31, 1990)

3.3 & 4.3     Articles of Amendment to Articles of Incorporation (Incorporated by reference to Registration Statement
              on Form SB-2, File No. 33-66190)

3.4 & 4.4     Articles of Amendment to Articles of Incorporation (Incorporated by reference to Registration Statement
              on Form S-3, File No. 333-30453)

3.5 & 4.5     By-Laws, as Amended (Incorporated by reference to Registration Statement on Form SB-2, File
              No. 33-66190)

3.6 & 4.6     Certificate of Designation of 1996 Series A Preferred Stock (Incorporated by reference to Form 8-K dated
              December 26, 1996, filed January 3, 1997)

3.7 & 4.7     Amendment to Certificate of Designations for 1996 Series A Convertible Preferred Stock

              (Incorporated by reference to Registration Statement on Form S-3, File No. 333-30453)

3.8 & 4.8     Certificate of Designation for 1999 Series A 8% Convertible Preferred Stock (Incorporated by reference to
              Form 8-K, dated February 3, 1999, filed February 11, 1999)

4.9           Indenture dated May 29, 1997 between Magnum Hunter Resources, the subsidiary guarantors named
              therein and First Union National Bank of North Carolina, as Trustee (Incorporated by reference to
              Registration Statement on Form S-4, File No. 333-2290)

4.10          Supplemental Indenture dated January 27, 1999 between Magnum Hunter Resources, the subsidiary
              guarantors named therein and First Union National Bank of North Carolina, as Trustee (Incorporated by
              reference to Form 10-K for the fiscal year-end December 31, 1998 filed April 14, 1999)

4.11          Form of 10% Senior Note due 2007 (Incorporated by reference to Registration Statement on Form S-4, File
              No. 333-2290)

10.1          Amended and Restated Credit Agreement, dated April 30, 1997, between Magnum Hunter Resources, Inc.
              and Bankers Trust Company, et al. (Incorporated by reference to Registration Statement on Form S-4, File
              No. 333-2290)

10.2          First Amendment to Amended and Restated Credit Agreement, dated April 30, 1997, between Magnum
              Hunter Resources, Inc. and Bankers Trust Company, et al. (Incorporated by reference to Registration
              Statement on Form S-4, File No. 333-2290)

10.3          Second Amendment to Amended and Restated Credit Agreement, dated April 30, 1997, between Magnum
              Hunter Resources, Inc. and Bankers Trust Company, et al (Incorporated by reference to Form 10-K for the
              fiscal year-end December 31, 1998 filed April 14, 1999)

                                       53
<PAGE>
10.4          Third Amendment to Amended and Restated Credit Agreement, dated April 30, 1997, between Magnum
              Hunter Resources, Inc. and Bankers Trust Company, et al (Incorporated by reference to Form 10-K for the
              fiscal year-end December 31, 1998 filed April 14, 1999)

10.5          Employment Agreement for Gary C. Evans (Incorporated by reference to Form 10-K for the fiscal year-end
              December 31, 1999 filed March 30, 2000)

10.6          Employment Agreement for Matthew C. Lutz (Incorporated by reference to Form 10-K for the fiscal year-
              end December 31, 1999 filed March 30, 2000)

10.7          Employment Agreement for Richard R. Frazier (Incorporated by reference to Form 10-K for the fiscal year-
              end December 31, 1999 filed March 30, 2000)

10.8          Stock Purchase  Agreement among Magnum Hunter Resources,  Inc. and Trust Company of the West and TCW Asset Management
              Company, in the capacities described herein, TCW Debt and Royalty Fund IVB and TCW Debt  and  Royalty  Fund  IVC,
              dated  as  of  December  6,  1996 (Incorporated  by reference  to Form 8-K dated  December 26, 1996,
              filed January 3, 1997)

10.9          Purchase and Sale Agreement, dated February 27, 1997 among Burlington Resources Oil and Gas Company,
              Glacier Park Company and Magnum Hunter Production, Inc. (Incorporated by reference to Form 8-K, dated
              April 30, 1997, filed May 12, 1997)

10.10         Purchase and Sale Agreement between Magnum Hunter Resources, Inc. , NGTS, et al., dated December
              17, 1997  (Incorporated by reference to Form 8-K, dated December 17, 1997, filed December 29, 1997)

10.11         Purchase and Sale Agreement dated November 25, 1998 between Magnum Hunter Production, Inc. and
              Unocal Oil Company of California (Incorporated by reference to Form 10-K for the fiscal year-end December
              31, 1998 filed April 14, 1999)

10.12         Stock Purchase Agreement dated February 3, 1999 between ONEOK Resources Company and Magnum
              Hunter Resources, Inc. (Incorporated by reference to Form 8-K, dated February 3, 1999, filed February 11,
              1999)

10.13         Agreement of Limited Partnership of Mallard Hunter, L.P., dated May 23, 2000 (Incorporated by reference
              to Form 10-Q/A for the period ended June 30, 2000 filed November 30, 2000)

21*           Subsidiaries of the Registrant
</TABLE>

* Filed herewith.

(B) Form 8-K's - None.

                                       54
<PAGE>

INDEPENDENT AUDITORS' REPORT


Board of Directors and Stockholders
Magnum Hunter Resources, Inc.


     We have audited the  consolidated  financial  statements  of Magnum  Hunter
Resources,  Inc. and subsidiaries as of December 31, 2000 and 1999, and for each
of the three years in the period ended  December  31, 2000,  and have issued our
report thereon dated March 20, 2001.  Such  financial  statements and report are
included  in your Annual  Report on Form 10-K,  and are  incorporated  herein by
reference.  Our audits also included the financial  statement schedule of Magnum
Hunter  Resources,  Inc.  listed  in the  accompanying  index at Item  14.  This
financial statement schedule is the responsibility of the Company's  management.
Our responsibility is to express an opinion based on our audits. In our opinion,
such  financial  statement  schedule,  when  considered in relation to the basic
consolidated  financial  statements  taken as a whole,  presents  fairly  in all
material respects the information set forth therein.





DELOITTE & TOUCHE LLP





Dallas, Texas
March 20, 2001

                                       55
<PAGE>

                        Valuation and Qualifying Accounts

                                ($ in thousands)



For the year ended December 31, 2000:
<TABLE>
<CAPTION>
<S>                                           <C>                <C>              <C>                 <C>
                                                   Balance at        Additions
                                                  Beginning of       Charged to        Deductions       Balance at end
                 Description                         Period           Expenses          Writeoffs          of Period
---------------------------------------------  ------------------ ----------------  -----------------  -----------------
Accounts receivable, trade                             $ 166           $   80            $ (196)          $      50
Current portion of long-term notes                       790              384                (4)              1,170
 receivable
</TABLE>


For the year ended December 31, 1999:
<TABLE>
<CAPTION>
<S>                                              <C>               <C>             <C>                  <C>
                                                   Balance at        Additions
                                                  Beginning of       Charged to        Deductions       Balance at end
                 Description                         Period           Expenses          Writeoffs          of Period
---------------------------------------------  ------------------ ----------------  -----------------  -----------------
Accounts receivable, trade                             $ 166           $    -            $     -          $     166
Current portion of long-term notes                       790                -                  -                790
 receivable
</TABLE>
                                       56
<PAGE>
                                   SIGNATURES

     Pursuant to the  requirements of the Section 13 or 15 (d) of the Securities
and  Exchange  Act of 1934,  the  Company has duly caused this Form 10-K/A to be
signed on its behalf by the undersigned, thereunto duly authorized.

MAGNUM HUNTER RESOURCES, INC.


        /s/Gary C. Evans
By: __________________________                                 June 6, 2001
     Gary C.  Evans, President & CEO



     In accordance with the Exchange Act, this Form 10-K/A has been signed below
by the following  persons on behalf of the Company and in the  capacities and on
the dates indicated.
<TABLE>
<CAPTION>
<S>                                      <C>                                              <C>

Signature                                                   Title                               Date
--------------------------------------------------------------------------------------------------------------------

/s/Gary C. Evans
______________________                           Director, President                        June 6, 2001
Gary C. Evans                                    Chief Executive Officer


/s/Matthew C. Lutz
______________________                           Chairman of the Board and                  June 6, 2001
Matthew C. Lutz                                  Executive Vice President of
                                                 Exploration and Business
                                                 Development


/s/Chris Tong
______________________                           Senior Vice President and                  June 6, 2001
Chris Tong                                       Chief Financial Officer




/s/David S. Krueger
______________________                           Vice President and                         June 6, 2001
David S. Krueger                                 Chief Accounting Officer


/s/Morgan F. Johnston
______________________                           Vice President, General Counsel            June 6, 2001
Morgan F. Johnston                               and Secretary


/s/Gerald W. Bolfing
______________________                           Director                                   June 6, 2001
Gerald W. Bolfing


/s/Oscar C. Lindemann
______________________                           Director                                   June 6, 2001
Oscar C. Lindemann


/s/John H. Trescot, Jr.
______________________                           Director                                   June 6, 2001
John H. Trescot, Jr.


/s/James E. Upfield
______________________                           Director                                   June 6, 2001
James E. Upfield
</TABLE>

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